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PGCE 2010
- Conference date: 29 Mar 2010 - 30 Mar 2010
- Location: Kuala Lumpur, Malaysia
- Published: 29 March 2010
61 - 80 of 100 results
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Influence of Pre-Existing Faults in Emplacement and Variation of Toc% in Pabdeh Formation Throughout Northern Dezful Embayment
More LessIn the petroleum systems ,understanding the process of sedimentation and paleogeography, which control the distribution and quality of source rocks ,reservoirs and cap rocks is necessary. Although climatic conditions, transgressions and regressions control the oxic and anoxic conditions but some geological settings and their structural history are considerable for sedimentation of source rocks. In this study ,using the neural network TOC value of Eocene pabdeh formation in northern Dezful Embayment is located in the Zagros petroliferous province is calculated relationship between TOC and basement faults was studied. The basement of Dezful Embayment is not integrated, and has staircase status. Northern part of this area is bounded by MFF(mountain frontal fault), ZFF(zagros foredeep fault) ,Balarud and Hendijan basement faults. The Separation of blocks by thrust faults caused differences in rate and type of sediments. Tectonic phases and depth variations have affected lithofacies pattern and in result of,They played role in organic content of rocks. The reactivation of faults specially in Hendijan lineament and vicinity to palaeohighs caused for increasing of geothermal gradient and maturation in pabdeh formation that presumably have led to enhance oil production locally and consequently, decreased TOC % in some oil wells.
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Source Rock Evaluation in the Southern Dezful Embayment
By M. ShayestehWire line tools are known as advanced and economic methods for formation evaluation of depositional basins. Wire line logs and data can be used to recognition of oil generation potential in a source rock . source rocks exhibit various especial properties in wire line logs Also their ability to oil generation can be recognized by hydrogen percentage (as a qualitative indicator) and total volume of organic matter(as a quantitative indicator ). A method is known as "ΔlogR" organized for" TOC" calculation . Another method is for neural network. This article explain the usage of there methods in detail to determine the volume of "TOC" in different source rocks ( Papdeh , Gurpi & kazhdumi ) in Aghajari , Parsi , Pazanan & Karanj fields in the southern Dezful embayment.
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Survey Design and Evaluation for Advanced Marine Acquisition in Geologically Complex Areas
Authors Åsmund Drottning and Endre Bergfjord and Mike BranstonThe goal of this study is to present a survey evaluation and design (SED) methodology that determines which strategy will give the best return on investment (ROI) for a geologically complex area, in this case a marine, sub-salt reservoir. The key objectives within this study are to characterize the impact each survey strategy has on the illumination of the target horizon, to quantify the improvement in seismic data quality and establish which strategy gives the best ROI.
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Pipeseis VI VSP as Challenging Method for High Accuracy Target of Horizontal Well
Authors Tiur Aldha, Juniza Jamaludin and Gunawan Taslim and Anis ShahabThe Vertical Incident (VI) survey was designed to have the walkabove Vertical Seismic Profile (VSP) source positioned vertically above the downhole receiver in highly deviated well to insure that the direct arrival travel path from source to receiver is close to vertical. In early 2009, it had been used in one high deviated pilot well prior to drill horizontal well in offshore Malaysia where to place a good oil reservoir along the well path accurately. In order to maximize the data quality and to reduce the risk of getting the downhole receiver stuck in the hole, the survey was recorded using Multi Level Receiver (MLR) string consisting of 2 x three component fixed ESR downhole geophone receivers using the PipeSeis technique, whereby the receiver array is deployed inside the drill pipe. The accurate velocity information from this VI VSP helps make crucial decision for horizontal well planning and better resolution for fault imaging.
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Geometry Charecterization in Ax Field
More LessThe Malay Basin is underlain by a productive, oil and gas-prone, nonmarine Cenozoic section. Characterising I Group channel morphology in AX Field is the main target of this thesis. A successful study of seismic geomorphology depends not only on knowledge of sedimentological, geomorphologic principles and the local geological setting, but also on quality of the seismic. 30x30 km three dimensional seismic surveys were used to study the stratigraphic record within I Group. Horizon slicing concept was used in this project; it depends on horizon and seismic data quality. Horizon slicing on full stack volume is useful in channel detection, while on structure volume is useful in channel width measurement. Straight and meandering channels are the main patterns recognized within I Group. Channels widths are ranging from 300m to 700m. Channels thicknesses are estimated using Spectral decomposition technique. The range of channels thickness is 20m-30m. Data of four exploration wells are useful to compare the real channel thickness with the estimated, when channels are drilled. Deposition environment within I Group is fluvial to tidal environment, means AX field is located close to the shore line at the time of I. Basin ward direction is to the east or south east. Seven main fluvial channels have been detected. Base of each fluvial channel considered to be sequence boundary. According to 3rd/4th order of sequence stratigraphy concept, eight sequences have been interpreted within I Group.
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Fluid Facies Prediction Through Avo Inversion in Offshore Sarawak
Authors Yusliza M. Sufian and Yeshpal SinghAVO inversion and validation of seismic amplitude study was carried out in a Sarawak Block over two prospects for derisking. The main objective of the study is to integrate seismic, geological and well information for identification of hydrocarbon reservoirs over the prospects. AVO inversion is a relatively new technology in the industry and has potential to provide more quantitative information than conventional AVO analysis. The standard AVO analysis is used to improve the understanding of the subsurface and in reducing geological risk. However, standard AVO analysis has many disadvantages and often used qualitatively. In some cases, it may even produces false result due to amplitude tuning and qualitative match with forward modeling from well data. AVO inversion overcomes most of the said disadvantages of conventional AVO. It includes the integration of the best of inversion of offset/angle gathers simultaneously whilst exploiting the full information within the seismic, log and relevant geological information available in terms of structure as well as stratigraphy. Fluid facies prediction using 2D probability density functions (PDF) of inversion attributes was modeled at well locations. The pdfs are classified based on facies and applied on 3D inversion attributes to estimate facies probabilities and then most likely facies cube in the area of interest. Analyses are then validated by the hydrocarbon sand intervals of the drilled wells in the study area. Stratal slicing analysis along with 3D visualization helps in further refining the analyses. It can be noted that AVO inversion results helped in predicting probable location of hydrocarbon bearing sands and hence better well placement. One of the prospects was drilled based on the result and the post drilling results validates the predicted facies.
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An Efficient Way to Characterize Complex Reservoirs Through Downhole Fluid Properties Measurement
Reservoir connectivity and compartmentalization are main challenges during the field development plan. High resolution logs and seismic interpretation are usually used to characterize reservoir complexity. However, similar to other interpretation methods, they have some degree of uncertainties. Reservoir pressure and fluid communications are therefore crucial to prove reservoir connectivity, especially in complex reservoirs. In offshore Peninsular Malaysia, oil field X has a big structure covering an extensive area with East- West elongated anticline and North-South trending faults. The reservoirs are tidally influenced mouth bars deposited within estuarine or bay fill environment. The reservoir fluid is known to have large variation of CO2, waxy, viscous, and low Gas-Oil-Ratio (GOR) based on the early appraisal well production tests. Currently, the field is undergoing a series of appraisal wells drilling program for delineation and reservoir data acquisition. Apart from the data quality, cost and timing are the key consideration for getting early reservoir fluid properties as the field is geared for the early first oil. The challenge is to obtain critical reservoir fluid properties such as CO2, GOR, fluid density, fluid compositions i.e. C1 to C6+, quickly and efficiently. This information is required for reservoir modeling and it can also be used to confirm reservoir connectivity in terms of fluid communication between fault blocks as previously interpreted in the structure map. The conventional approach of collecting downhole or surface samples during Wireline Formation Tester (WFT) or production test and then have these samples sent for lab PVT analyses is expensive and time consuming. It involves contract preparation and bidding, lab queue system and also subject to samples quality and handling risks. Alternative ways to obtain in situ reservoir fluid properties quickly, accurately and representative of the reservoir have been explored, used and tested in this paper. This work illustrates the use of Downhole Fluid Analyzer (DFA) data to better characterize reservoir fluid complexity in such a way that it can completely change the current perspective of reservoir fluids. The new generation of WFT together with DFA data allows us to accurately quantify the CO2 content which is essential for facilities and pipeline designs and material selections. In addition, this technology provides high quality real time fluid properties with significantly less contamination. This is an excellent alternative way to obtain high quality reservoir fluid properties without production test and laboratory analysis. The small variance between the DFA and the lab measured data has increased our confidence to extend the application of this tool in the appraisal wells program where no production test or fluid sampling is planned. This has led to the early understanding of the reservoir fluids system in terms of GOR, light ends and heavy ends components, density/API, viscosity, CO2 variations vertically and areally without having to conduct unnecessary production test or downhole fluids sampling. It is a cost saving in a way.
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Application of High-Resolution Sequence Stratigraphy (Hrss) for Reservoir Prediction in Group L & M, Block Pm309, Malay Basin
More LessThe high-resolution sequence stratigraphic (HRSS) classification and correlation techniques, based on the principles of strata base level, volumetric partitioning and facies differentiation, can effectively improve the prediction of reservoir and increase opportunity of finding the subtle oil and gas reservoirs. Calibrating among core, well log correlation and seismic interpretation, identification of key sequence interfaces and reservoir mapping have successfully been applied to predict the distribution of effective reservoir in the Group L & M of Block PM309 in Malay Basin. This is the first detailed study done in Group L & M since its discovery and was conducted at the southeast of PM309, near Malaysia-Indonesia boundary. Seligi and Pulai are the two oil fields have been used in this study. The seismic stratigraphic units of Group L (younger) and M (older) were deposited in the lacustrine rift basin during the synrift phase. Below Group M, eight fourth order sequences were identified which mainly comprised of alternating thick sandstone and lacustrine shale packages. From Top Group M to L20 sand, two fourth order sequences were identified. The Group L facies include non-marine lacustrine offshore to deltaic, braidplain and minor lakeplain. Progradation of lacustrine sediments started from Top M up to the L70 sand. Above the L70 sand is a third order sequence boundary. Another third order sequence boundary was interpreted to be above the L20 sand. L20 sand package consists of thick laterally aggrading braided stream sandstone. Above the L20 sand, the younger sequences retrograde up to the top of the Group L. Twenty wells and four core description have been conducted in this study. Interpretation on L20 and M20 sand was done and correlatable with the well log. Based on the study, stratigraphic hydrocarbon traps was represented by sandstone bodies of deltaic and shoreface origin. From the deltaic environment, the traps are mostly from distributary channels and mouth bar bodies. The mouth bars (i.e M20 sand) were identified by their upward-coarsening trend from well logs and the deposition evolves mostly during the highstand systems track. Lacustrine shales act as seals to trap the hydrocarbon.
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The Importance of Including Overburden and Survey Illumination Effects in Reservoir Seismic Simulation
Authors Åsmund Drottning and Isabelle Lecomte and Mike BranstonThis paper explores an alternative approach to 3D and 4D seismic modeling based on the SimPLI (Simulated Prestack Local Imaging) PSDM simulator technique introduced by Lecomte et al. (2003), Lecomte (2004), and presented in more detail in Lecomte (2008). The method is both computationally efficient, allowing quick, repeatable, multi-scenario analysis, and allows the integration of illumination constraints from the survey and overburden, making it particularly useful for time-lapse seismic analyses. The PSDM simulator is a rapid and cost efficient solution for realistic simulation of seismic data that goes far beyond classic 1D trace modeling and allows comprehensive sensitivity analyses by forward modeling in a time frame not afforded by Finite Difference Modeling (FD). The modeling concept and workflow was discussed by Gjøystdal et al. (2007). Here we present specific examples from synthetic models as well as a real data example from the Norne field offshore mid-Norway. These examples will focus on the integration of survey data, overburden properties, rock properties and fluid simulator data into the 3D and 4D seismic modeling schemes, and discuss their impact on the seismic responses.
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Reservoir Characterization in the West Baram Delta Through Rock Physics Constrained Data Integration
Authors Yeshpal Singh and Kamal Arif B.M. Amin and Erick AlvarezIt is well established fact that seismically derived petrophysical properties provide a more complete description of the reservoirs than what could be done through the conventional statistical techniques based on wells and seismic maps. The main objective of present study is to determine which petrophysical parameters control the reservoir quality and how these are related to the elastic properties that control the seismic propagation. Constraining a geological model using seismic derived properties always represents big challenges, mainly because of the uncertainties associated with the seismic properties, and the differences in resolution of the measurements involved in the process. This can only be achieved if a complete and well organized integration between the different disciplines involved is achieved. We present the methodology and results that allowed conditioning the geological model using seismic derived properties in the Siwa field, Sarawak basin, Malaysia.
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A Comparison of Porosity Modeling Involving Well and Core Data with AI from Inversion in Temana Field; A Case Study
Temana field is located approximately 30km offshore Bintulu which is in the Balingian PSC, subblocks 4Q-29 and 4Q-30 with the water depth of 96 ft. The field is divided into 3 hydrocarbon accumulation namely the Temana West, Temana Central and Temana East; each area has different deformation style and fault patterns (Figure 1.0). The Temana field was discovered by drilling the Temana-1 well in 1962 and brought into production in 1979. Temana Saddle has been discovered by drilling the appraisal well (Temana-72) in 2004. The outcome from the appraisal campaign indicated that the I-65 reservoir is the most promising reservoir compare to the other reservoirs in the Temana Saddle area. An FDP (Field Development Plan) study was initiated in 2005 and
the 1st oil from this study was in Q1 2006 (Figure 2.0). 3 new development wells namely Temana-73ST1, Temana-74ST2 and Temana-51 ST2 were drilled in Phase 1. The highest production was from the Temana- 73ST1 tested at ~3600 bopd and the accumulative production of 4.1 mmstb as of April 2009 (Figure 3.0). The dynamic simulation shows a pressure drop of ~250 psi and an increasing GOR trend approaching RMP limit (1500 scf/stb) was observed. The Phase 2 FDP study was started in 2007 after the completion of Phase 1 drilling and focusing on the pressure maintenance study. The study involves updating the static model by incorporating the new well data to update the STOIIP. The standard workflow of static modeling (involving the well and core data) is followed as in previous Phase 1 study (Figure 4.0). At the property modeling stage, the same algorithm was used but using 2 different methods; 1) to model the porosity based on the well data and propagated by variogram and 2) to model the porosity by incorporating the AI derived porosity data constrained with log derived porosity data. The main aim of this study is to compare the porosity distribution from both methods whether it does match with the porosity in the new post drilling well. The cross plot between well log porosity and AI gives a good correlation of 87% (Figure 5.0). From the study, the porosity model which was generated based on well data and propagated by the variogram give s a good porosity match with all wells (Method 1), where as the model that was generated based on the inversion (Method 2) give a good porosity match only at the well locations that have checkshot and sonic data, and fair to good correlation in the other wells (Figure 6.0). Volume calculation shows an increase of 28% and 17% in STOIIP using method 1 and 2 respectively (Table 1.0). In conclusion, AI derived porosity model must be used provided most of the wells have checkshot and sonic data to address the uncertainty.
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Porosity Prediction from Acoustic Impedance (AI) in Temana Saddle
Temana field is located approximately 30km offshore Bintulu which is in the Balingian PSC, subblocks 4Q-29 and 4Q-30 with the water depth of 96 ft. The field is divided into 3 hydrocarbon accumulation namely the Temana West, Temana Central and Temana East; each area has different deformation style and fault patterns (Figure 1.0). In 2004, an appraisal well namely, Temana-72 was drilled in Temana Saddle area which is located in the southwestern part Temana Central. The outcome from the campaign indicates that the I-65 reservoir is the most promising reservoir compare to the other reservoir. A FDP ((Field Development Plan) study was initiated in 2005 and the 1st oil from was in Q1 2006. The Phase 2 FDP study was started in 2007 after the completion of Phase 1 drilling focusing on the pressure maintenance. A revised static model building incorporating three more appraisal wells information is the major objectives. Seismic data has proved to be a critical tool in predicting the reservoirs properties beyond the
limitation of the well control. The changes in seismic response could be related to changes of lithology, fluid contents or variation in reservoir properties. The used of seismic driven properties integrated with the well data are common in reservoir modeling building either as a trend input along with geometry constrained by structural interpretation. This paper will discuss on the inversion of the post-stack seismic reflection data into impedance data. Seismic and well integration workflow for reservoir model building as shown on the next page has been established (Figure 2.0). The inverted AI was transform to reservoir properties particularly porosity in Temana Saddle area. This seismic predicted porosity has been use as a trend input in reservoir model building together with the well log input to produce the 3D porosity model. Well log data QC analysis of Temana-72 indicates that porosity can be predicted from Acoustic impedance (Figure 3.0 and Figure 4.0). Predicted porosity can be used as trend input for reservoir model building in and around Temana -72 area. Correlation coefficient is 0.86. This study is done to provide a predicted porosity value for I60 and I65 derived by seismic data in order to proper propagate the porosity value between the wells in the reservoir model (Figure 5.0). The porosity prediction using the acoustic impedance give good result at the well location that have sonic and checkshot and fair to good correlation in the other wells.
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Dual-Sensor Technology in Marine Seismic Acquisition Applied to New Play Identification in Central Luconia Province, Offshore Sarawak
More LessCentral Luconia Province in offshore Sarawak Basin has predominantly in the past been the target of numerous exploration campaigns. Past efforts in this tectono-stratigraphic province focused mainly on Miocene carbonate buildups (Cycle IV & V) ranging from platforms to pinnacles. Discovered fields, the likes of Bijan, Jintan, F12, F6, E8, PC4 and such have proven commercial quantities of hydrocarbons in the carbonates. The pre-carbonate clastic sequences have also been proven prospective but the exploration efforts to date have been impeded to a large extent by seismic imaging issues. PETRONAS has in the past, considered various technological advancements encompassing both acquisition and processing methods thought to be capable of illuminating the pre-carbonate plays. Advance processing techniques helped but the fundamental issues of energy absorption and dispersion rendering ‘wiped-out zone’ and severe seismic attributes attenuation below the carbonate still remain. The idea of dual-sensor (hydrophone and velocity sensors) technology has been discussed as early as 1964 by Schneider and Backus. Yet the issues of resultant noise from the vibration of towed streamer and sensors render the data unusable. Two different approaches were formulated for producing usable dual-sensor data; i.e. simultaneous towing of streamers at different levels and collocation of both sensors in the same streamer. PETRONAS opted to test the latter approach and seek to quantify the improvement in the seismic data image quality. To this end, a marine 2D seismic acquisition initiative utilizing dual-sensor technique was executed in Central Luconia area repeating vintage 1998 2D lines acquired conventionally. The original acquisition specifications were maintained as much as possible and both datasets were processed following similar sequences so that any improvement can be directly attributable to the differences in acquisition technologies. The primary target was imaging the pre-carbonate clastics at 1.5 seconds to 2.5 seconds in two-way time. Indeed, significant improvement of the dataset was observable through out. The amplitude spectrum shows marked differences between the newly acquired dual-sensor and reprocessed vintage 2D datasets. SRME procedure benefited from the wider range of bandwidth accorded by the dual–sensor technique dataset. In the examples, the differences both in the single shot gather and stack section are shown. Accurate Q estimation proves useful in preserving the deeper primary reflections. The dual-sensor dataset gives improved image of deep events as well as the capturing of more usable lower frequency data. Thus, we conclude that the technology is a workable step ahead in imaging pre-carbonate geology in Central Luconia Province.
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Overview of Remaining Exploration Potential Plays in East Sabah Basin- Malaysia
Authors Robert Wong and Meor SyazwanThe East Sabah Basin consists of two sub-basins-the Sandakan sub-basins and the South Dent Trough. So far most of the wells drilled in the East Sabah Basin were focused on the northern part of the Sandakan sub-basin, targeting the obvious Middle-Upper Miocene deltaic play within structural closures. Some oil and gas were discovered so far with none of the fields developed yet. The paper will focus on the whole of the East Sabah basin which includes the Sandakan sub-basin and Sabah Trough. Within the Sandakan basin, the untested plays include the stratigraphic traps of turbidite sands which include slope fans and basin floor fans. These new plays are currently identified by only 2D seismic data. The only well drilled close to these play is Gem Reef-1 which encountered gas shows in these similar sands which pinch out onto a volcanic high. But the well was not positioned in the best location to test these sands. Hence these new plays present the new exploration opportunities. One well was drilled in the South Dent Trough but did not encounter any hydrocarbons. The main reasons are the questionable structural closure due to the poor velocity control, poorly defined trap due to poor data quality and the absence of the reservoirs. The well is located up-dip in a slope setting thus not much reservoir development is expected. The sand development should be better downdip in the basin floor fan setting. Acquisition and processing of new, high quality regional seismic data over the eastern and southern parts of the East Sabah basin were carried out in 1999 and 2004. The objective is to upgrade the prospectivity of this exploration-neglected area. Coupled with regional geological study in the East Sabah Basin, the interpretation of these newly acquired seismic data has unraveled new, untested exploration plays, which include both structural and stratigraphic plays. The deep Middle Miocene structural play with 4-way dip closures is observed within the southeastern margin of the Sandakan sub-basin. These structures were generated during the Pliocene uplift together with the creation of the onshore Dent Anticlinorium. This structural trend is expected to continue in the Dent onshore area but at shallower level. The deep Middle-Upper Miocene turbidite play, determined by seismic facies analysis and amplitude extraction, is located in the eastern portion of the South Dent Trough. The delineation of this play, expressed by the gently mounded seismic facies, can be further enhanced by 3D seismic coverage. Finally, the Middle Miocene pinnacle reef play, clearly imaged by the new seismic data as mounded facies, is present in the central area of the South Dent Trough. Covered by marine shales, the pinnacle reef poses as a valid play. The only well drilled in this area only bottomed just above the reefal buildup after encountering some limestone stringers.
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Paleofacies Mapping of Balingian Province using 3D Megamerged Seismic Data
More LessThe Basin Assessment Group of PREX, PMU embarked on merging of eighteen 3D datasets in the Balingian Province, part of the Sarawak Basin in late 2005. The 3D datasets used are of various vintages from 1984 to 2004 covering an area approximately 11000 sq km over 27000 sq km of Balingian province. This 3D mega merged data was utilised in the interpretation and mapping project in 2008 to establish an updated regional correlation and paleofacies and identify new hydrocarbon play, leads and prospects. This mega merged data allowed visualization of the regional depositional facies in three dimensions. Previous paleofacies mapping of the Balingian Province was based mainly on drilled locations with well logs and biofacies. It does provide a broad paleofacies maps of the Balingian Province, especially for Cycle I and Cycle II megasequences. With the advent of new 3D megamerged seismic data, paleofacies mapping can then be carried out with better coverage and detail based on seismic facies analysis calibrated to the numerous wells drilled in the area and updated biofacies. Furthermore, sequence stratigraphic cross-sections can be generated in any directions. Facies change can be observed easily based on the change in seismic facies and compared with the well correlation panels. In this paper, various seismic facies representing coastal plain, coastal to shallow marine and carbonate facies are described. Five paleofacies maps have been created-Cycle I, II, III, IV and V to depict the five main megasequences in the Balingian Province. The change in depositional direction from west to east in Cycle I, and Cycle II times to generally south to north in Cycle III, IV and V times is due to a major uplift at end of Cycle II. Some differences are obvious when compared with the previous paleofacies maps and they are highlighted in this paper. Furthermore, a new west to east chronostratigraphic chart is also created to depict the changes in depositional environment more accurately including showing the areas of uplift and erosion and carbonate deposition. More importantly, new plays and leads are also identified especially the Cycle III pinnacle reefs which are yet to be tested in the Balingian Province.
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Fractured Crystalline Basement Study: The First Field Technique Used Onshore East Coast Peninsular Malaysia
A unique field technique has been implemented in study of fractures as the major contributor to secondary porosity in crystalline basement. Crystalline basement in the Malay and Penyu basins consist of metamorphic and Pre-Tertiary igneous rocks. These rock types crop out onshore in the East Coast, Peninsular Malaysia. There are four different lithologies in this study area; granitoid, metaclastic, metavolcanic and crystalline limestone, which are devoid of primary porosity. Figure 1 shows the location of the study area. No significant outcrops are available in the Eastern Belt between Kuantan and Endau where the Quaternary coastal plain is wide. Tertiary structural events recorded from PM offshore basins were the latest tectonic deformation which caused its adjacent onshore structure to be reoriented – creation of fractures. The main focuses in this study are fracture style, trend, intensity and distribution from the four rock types. The selection of outcrops are based on their closest proximity to Malay and Penyu basins.The methods used: 1. Fracture type and density study 2. Fracture attitude and dip study The fracture type and density study involved detail measuring and counting of fractures (perpendicular to traverse line and 30° or 45° to traverse line) in the representative localities. The measurement was conducted with adequate areal coverage at each location and well distributed over the study area. Fractures are classified into four groups; wide open, open, tight (visibly open) and closed. The fracture intensity is displayed as one of fracture properties and ranked. Figure 2 shows an example of fracture density and aperture for Pulau Kerengga Besar, Pulau Redang, Terengganu. Average of 100 fracture orientation measurement were collected from each area for fracture attitude and dip study (Table 1) and plotted on Schmidt strereonett (Figure 3). The fracture connectivity is effectively shown and added up as another important element in fracture properties. All these fracture properties were classified and ranked in the order from very good to very poor categories. The most promising lithologies are very fine - fine grained metaclastics and cretaceous granite exhibit high fracture intensity, open fractures and fracture intersection.
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Seismically Driven Reservoir Fractured Reservoir Characterization Using an Innovative Integrated Approach: Joanne Field, UK
Authors Abdel M Zellou and Jeff RossJoanne Field is located on the UKCS approximately 270 kilometres east of Aberdeen on a salt-cored four-way dip closed structure. Production comes from allochthonous chalks of the Upper Cretaceous Maastrichtian Tor Formation deposited by a series of stacked turbidite lobes originating from the northwest that cover the western and southwestern flanks of the structure. Unlike the better known chalk fields of Norway and Denmark, UK chalk accumulations suffer from a combination of generally greater depth of burial and lower overpressures resulting in significantly less matrix permeability. For this reason, fracture induced permeability enhancement is a critical determinant in separated non-commercial chalk accumulations from commercial ones. Although there have been three vertical and fifteen deviated wellbores drilled in the Joanne Field, there have been no dedicated fracture identification logs acquired in any well and oriented cores have only been acquired in four wells. This paucity of hard data on the density, orientation, and production impact of the fracture networks across the Joanne structure has necessitated the application of the Continuous Fracture Modelling (CFM) technique to predict fracture permeability distributions to aid in the construction of detailed
reservoir models for production simulation. For this study, the CFM approach combined the use of highresolution seismic attributes, well based geological information and production based data to create a neural network derived fracture model that honours all the available data and predicts areas of fracture enhancement away from well control.
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Petroleum Systems Analysis of West Africa Deepwater from Cameroon to Angola: A Systematic Approach to Identifying Exploration Targets
A petroleum systems review of West Africa deepwater, from Cameroon to Angola, was undertaken with the view of assessing the remaining potential and to determine areas for further investigation. With the wealth of exploration/production data available internally and from the public domain, a systemic approach was taken to obtain a ‘bird’s eye view’ of the geology of the margin and its petroleum systems. The study was also a means for identifying data and knowledge gaps where future studies may be focused. A chrono-stratigraphic chart for the entire West African margin provides the framework for further analysis. The chart was compiled mainly from public domain data, detailing out the main source, reservoir and seal rock units in a tectonostratigraphic
context. Information such as hydrocarbon occurrences (fields and discoveries) and wells drilled are pasted on the chart (both in printed and digital forms) for easy viewing. In its digital form, tabulated data for fields and discoveries are provided as hyperlinks to worksheets. Petroleum systems are defined by linking the reservoirs to their respective source rocks. A total of 24 petroleum systems, both proven and hypothetical are identified in all the major basins along the margin, from north to south: Rio del Rey, Douala, Rio Muni, Gabon, Lower Congo, Kwanza, and Namibe). Each petroleum system is illustrated in folio sheets, which provide details of the petroleum systems elements: source, reservoir, migration and trapping mechanism and timing, complete with a petroleum systems events chart. Besides the proven major petroleum systems, a number of hypothetical petroleum systems have been identified, which needed further investigation and validation. The chronostratigraphic charts and petroleum systems folios are used in
conjunction with a comprehensive GIS database that was established to aid further analysis of the margin.
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Biofacies Characterisation in the Marginal Marine Environments of the Malay Basin Using Agglutinated Foraminifera
More LessBenthic foraminifera have been widely used to interpret depositional environments within rock sequence. Due to the enclosed and paralic nature of the Malay Basin, it is difficult to define the biofacies zones based on calcareous foraminiferal assemblages alone. On the other hand, the agglutinated foraminifera are more useful in characterising different biofacies in the paralic setting such as the Malay Basin since they are well represented from marginal marine to bathyal environments (Figure 1). Three modern analogs localities were carried out for the biofacies study; Sedili Besar Estuary and its offshore areas, Klang-Langat Delta and Pahang River Delta (Figure 2). In this study, we used major agglutinated foraminiferal assemblages from selected modern environments to characterise different biofacies in the marginal marine paleoenvironments. Only the most common agglutinated foraminifera species with counts of more than ten are used for the groupings. Results of the Recent foraminiferal assemblages recorded from the modern environments are discussed here. Out of the three different localities, Sedili Besar Estuary covers the most detailed and widespread depositional facies within the marginal marine. Several biofacies zones can be differentiated based on the abundance of the main agglutinated foraminifera (Figure 3). The occurrences of agglutinated foraminiferal species such as Ammobaculites exiguus, Textularia sp and Arenoparrella mexicana can be used to differentiate the nearshore, shallow marine and brackish intertidal depositional settings. The distribution patterns of some agglutinated foraminiferal assemblages inferred from this study can also be used to imply water depth, salinity and sand distribution within the marginal marine environment. Thus, it could further improve our current understanding of different depositional environments in the Malay Basin and will lead to a more precise characterisation of the paleoenvironments.
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The Effects of Tectonic Evolutions on the Elastic Properties of Malay Basin
Authors Uzir Alimat and Shaidin ArshadA study has been undertaken to use the edited and conditioned log data from 48 exploration wells throughout the Malay Basin. The depth trends of elastic properties (density, ρ, compressional velocity, Vp and shear velocity, Vs) together with the porosity (ø) values of “pure” sand and shale lithologies of Malay Basin have been carried out using this database (Singh and Mohamud, 2008). Their study concluded that, the high values of Vp, Vs and densities along with low porosities exist at the deeper part of the basin. This is the normal trend worldwide. However, other external elements such as tectonic events, which may have some influence on the depth trends of elastic properties, were not considered in their study. The present paper will shed some lights on what the effects of such events may have on the variation of these properties along a stratigraphic horizon that crosses different tectonic zones. Malay Basin is known to have undergone a series of structural events. Major tectonic events which took place early to mid Miocene demarcated the SE portion from the NW portion, causing it (the SE part) to undergo a thermal/tectonic subsidence phase, accompanied by basin inversion (Figure 1). Special attention has been given to the prolific I-horizon which was penetrated by 23 wells out of 48 in the database. This horizon is well represented throughout the basin and has experienced periods of both relatively quiet and intense tectonic stresses. Ultrasonic measurements of core data from the I-Horizon are being collected to compare
with the log data to check for consistency. The authors believe that the tectonic evolution and stress level imposed on all the pre-inversion stratigraphic horizons and at the reservoirs level within the I-Horizon may have some influence on the reservoir’s elastic properties. Any marked differences in depth trends from two different tectonic environments along this horizon would cause some variations in the seismic responses. This may also include variations in the AVO trend, which is one of the main predictive tools for Direct Hydrocarbon Indicator (DHI) quantitative interpretation. Acoustic impedance (AI) of sand and shale has been chosen as the fundamental parameter used as the basis in analyzing the impact of tectonic activity on rock elastic properties in the Malay Basin. The true vertical depth (Depth) vs. AI trend was plotted for all the wells by using filtered end member data and the AI behavior was observed. The AI reflects the stiffness of the lithology and normally increases with depth. The comparative plot between these two lithologies for each well is shown in Figure 2. The distribution leads to a rather distinct demarcation between the southeast region marked as Zone A to the northwest and central region, which marked as Zone B respectively (Figure 3). Comparing the combined AI trends plots for all the wells for both zones had showed a contrasting regression line between sand and shale at depth greater than 1500m (Figure 4).
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