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PGCE 2004
- Conference date: 15 Dec 2004 - 16 Dec 2004
- Location: Kuala Lumpur, Malaysia
- Published: 15 December 2004
37 results
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Proper Treatment of Amplitude and Phase of Seismic Data for Preserving Geology
By Deva GhoshPreserving the amplitude and phase of Seismic data is of paramount importance in modem day data analysis and subsequent evaluation. Unlike previous years where the Seismic was used only to image and map structures, modem application ranges from lithology , fluid and pressure prediction, rock-property analysis extending as far as to reservoir and fluid monitoring (4D) at production stage .The processed and imaged seismic section has to represent geology. The high quality of modem 3D seismic data is enabling us to confirm old geological ideas and develop new concepts and models, particularly of deep water turbidtic depositional system. The data work flow we adopt in Carigali today , in order to meet this objective, would be to follow wave phenomena and
correct in a deterministic manner all the earth propagation and filtering effects. A seismic pulse is represented by its arrival time (T), its amplitude (A) and phase (phi). Currently we are generally using only T to map the structures and (sometimes) the amplitude to create amplitude maps. However, we should emphasize also the importance of phase information in seismic to well correlation, coherency sections for fault delineation and dip azimuth in fracture studies. Phase along with polarity is of significance in discriminating a hard from a soft impedance, in discriminating sands from shale’s or in flat spot identification. Likewise, another variable frequency defines resolution aspects in our ability to detect thin beds.
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Geocellular Modelling of the Fluvial Deltaic and Shallow Marine Reservoirs, Tangga Barat Field, PM313 Offshore Malay Basin
Authors K.J. Bate, G. Taslim and M.A.A. Halim and T.Y. HongThe Tangga Barat field discovered in 1985 by Esso Production Malaysia Inc well Tangga Barat-1A is one of a series of Middle Miocene Gas Fields aligned along the axis of the Malay Basin offshore Peninsula Malaysia. The reservoirs of this Greenfield range in age from mid Middle Miocene H Group shallow-marine sands, through the fluvial-deltaic dominated E Group, to the early Upper Miocene D Group neritic sands. The primary reserves of the Tangga Barat field are contained within the E Group reservoirs that contain circa eighty percent of the hydrocarbons in place. However, a relatively high degree of uncertainty is inherent in the subsurface understanding as a result of both the low density of well coverage and due to gasshadow effects immediately overlying the field that degrades the seismic image of the reservoirs. This paper focuses on the attempt to quantify the subsurface uncertainty by the construction of a 3D Geological Model utilising the results of the interpretation of a recently acquired 3D seismic survey and integrated with all log, engineering and drilling data. The paper also summarises the impact of the model on the Field Development Plan for Tangga Barat.
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Depositional Model of a Sharp Base Progradational Estuarine Sandstone: A Case Study of B55M Reservoir — West Patricia Field
Authors T. Prasetyo, L.B. Leong and A. Firth and M.R. LasmanThe Middle Miocene B5.5M sand is the secondary reservoir in the West Patricia Field. It is currently producing approximately 3000 BOPD from two wells. The B5.5M core from WPA-3 well consists of alternating non-calcareous sandstones and shale drapes, with sharp sand and shale boundary at the top of the sand (Fig. 1). However, the base of the sand is gradational with the underlying shale. The presence of Florschuetzia trilobata and Polysphaeridium sp suggest an estuarine depositional setting. The B5.5M sand log signature displays an alternating fining and coarsening up-wards pattern which is interpreted to represent cut & fill channel and river mouth bar facies respectively (Fig.2). These observations suggest that the B5.5M sand was deposited as stacked estuarine river mouth bars and cut & fill channels, in an overall progradational succession.
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Structural Style and Hydrocarbon Potential of the Dent Peninsula, Eastern Sabah
More LessThe eastern Sabah area has undergone several deformational phases. The latest is the Pliocene-Pleistocene deformation, with the maximum stress in NNW direction. This deformation was responsible for shaping the present day landscape of eastern Sabah and also responsible for reactivation of old structures and the formation of latest structures that exist today. In the offshore area, the structures that have been drilled for hydrocarbon are mostly faulted anticlines formed by a combination of wrenching and syn-sedimentary growth-faulting. The hydrocarbon has been discovered in middle to upper Miocene sand, which is equivalent to the onshore SegamalTanjong formations and the Dent Group. This indicates the existence of an active petroleum system is operating in the area. This is also corroborated by the presences of hydrocarbon seeps in the onshore area. The similar structural style is also observed in the onshore eastern Sabah. From structural interpretation of SAR images, it is found that the area is dominated by strike-slip regional faults trending in NE-SW, NW-SE and NNW-SSE. The observed structural grains along the faults indicate wrench movement, which may favor the formation of hydrocarbon traps. There are several types of structures associated with these faults, that are of interest to petroleum exploration such as en echelon drag folds and fault bounded anticlines. Most of these wrench related structures and a few others are common in this area. The outcrops of the Dent Peninsula, eastern Sabah is the uplifted portion of the strata forming the Sandakan sub-basin, which collectively known as the Dent Group. It comprises the Sebahat, Ganduman and Togopi formations, which ranges from middle Miocene to Pleistocene. The succession has been interpreted as a prograding delta, with the Sebahat being the prodelta and marine facies, overlain by the coastal and deltaic Ganduman formation forming the top-set. The Togopi is unconformable upon the underlying formations, marking a major tectonic event in the Late Miocene to Pliocene. The unconformity below the Togopi formation has been interpreted as a major sequence boundary in eastern Sabah. It has been a significant sealing layer for hydrocarbon in the offshore area, where most of the discovered hydrocarbon is trapped by this unconformity. Since its coverage extend into the onshore area, it is possible to find hydrocarbon trapped in the structures below it.
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Convergence Towards Reducing Exploration Stratigraphic Play Risks
Authors V. Kong and N. Alwi and A. SetiawanMuch geophysical analyses have been conducted on the northeastern flank of the Betty field. This flank covers the extension to the east, the slightly deeper Betty Timur area where hydrocarbons were found in the same Miocene formation as that of the Betty field some 11 km away. The earlier relatively simple analysis using full-stack acoustic impedance data led to the identification of a number of potential hydrocarbon-bearing geo-bodies which could only be valid if explained from a stratigraphical trapping mechanism. The availability of shear sonic logs in the Betty Timur recent wells and the angle sub-stacks of the seismic data afforded us more rigorous analyses using a number of techniques to reduce uncertainties in the search for potential hydrocarbon-bearing zones.
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The Evolution of Kinabalu Reservoir Modelling, “from Multiple to Single”
Authors E. Akien, G. Philip and A. Cullen and S. ToulekimaThe Kinabalu field is located offshore Sabah, 55 km KM WNW of Labuan Island. The field was discovered in 1989 by well KN- 1, which found several stacked Late Miocene reservoirs. The reservoirs are late Miocene sediments deposited in the upper to lower shoreface environments. The hydrocarbon accumulation occurs in a 3-way dip closure monocline in the hanging wall of a SW-NE trending growth normal fault. The Kinabalu field consists of is made of three accumulations, the Main, the Deep and the East, that contain 500 mmstb STOIIP. The STOIIP of the field is 500 MMstb, 80% of of which is oil in place located in the Main accumulation. Development of the Kinabalu field started in 1997 with development drilling of the Main accumulations. First oil was in December 1997. Historically the reservoirs in the Main accumulations were modelled individually owing to . This approach was followed because of limitations in computing power and because modelling packages at that the time could not handle listric dipping faults. Static and dynamic modelling were challenging since multiple models needed frequent updates had to be updated all the time which require extensive staff and computer time. This required lot of man power and consumed lot of time. Well planning using multiple single models was another challenge since a typical well in Kinabalu wells typically have has several targets. Also In addition, use of Excel spreadsheets to reconcile reconciliation of simulation output from individual models into a full field output was done using Excel spreadsheets, which made auditing difficult almost impossible and often introduced several errors. With The significant improvements in computing power and the advances ment in modelling packages and the push by the leadership team asked for a modelling approach combining that could combine simplicity and speed. meant a To achieve a new way of doing things, had to be found. The the team, therefore, came up with the idea of a “Kinabalu Mega Model”. The Kinabalu Mega Model (i.e. KMM) incorporates all the 35 oil-bearing reservoirs in the Main accumulations, . There are 35 stacked reservoir which are modelled in KMM, covering the depth range from about 4000 to 10000 ft tvdss. The aerial dimension of the model is 25000 ft x 8000 ft. Prior to upscaling, the static model has 3 million grid cells that are . The size of each grid cell before upscaling is 300 ft x 300 ft x 4 ft. After upscaling for dynamic modelling the size of each grid cell is 300 ftx300ftx 18 ft. In terms of static modeling workflow, this new mega model enables a better handling of structural uncertainty since all the reservoirs are now share an integrated into the same structural framework. Subsequently, the sensitivity to petrophysical properties across all reservoirs in different structural realizations can be tested. The model also provides a common platform for members of subsurface team and requires fewer people to maintain the project. This contributes to time saving and better data management. process. From the dynamic point of view, the availability of the KMM has simplified and speed up history matching and forecasting. Wells with completions in multiple reservoirs can be simulated with better accuracy than previously. Planning of future development activities are now very transparent to all multi-discipline team members. Lastly, we now have a very efficient tool for full field management. In conclusion the main contributions of the Kinabalu Mega Model are summarized below: 1. Increase modelling speed, which translates into time saving.
2. A simplified and transparent modelling methodology which requires less man power, yet still retains accuracy. 3. Uncertainty ies modelling and data management are handled in a very efficient way. 4. The mega model has also given the team the holistic view when it comes to future development in Kinabalu. (The team used to look at individual parts of the field).
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Furthering the Shallow Clastic Play in the Central Luconia Province — the Kumang Stratigraphic Trap
Authors A. Yusof and I. MohamedThe continental shelf of Sarawak Basin is considered a sub-mature area for the oil and gas exploration. Hydrocarbons are found in the Oligocene to Early Miocene clastics (Balingian sub basin), Middle Miocene carbonates (Luconia sub-basin) and Middle Miocene to Pliocene clastics of (Baram Delta sub basin). The early exploration wells were drilled on simple structural/fault closures as well as high relief carbonates. These conventional traps are normally associated with higher chance of success to find hydrocarbons. On the other hand, stratigraphic traps are considered very risky. The high uncertainty in the trap definition and difficulty in reservoir prediction deemed the stratigraphic play as unattractive. Utilizing the advances of the geophysical tools such as DHI mapping, AVO, Seismic Inversion and Seismic/Sequence Stratigraphy concepts have led to the identification and discovery of Kumang stratigraphic trap in the Central Luconia Province. Kumang is a low relief pinch-out stratigraphic trap. It is located in a depression, at the southern flank of West Luconia. The prospect is covered by 1988 and 1998 2D seismics with a grid spacing of 3 by 3 km. Kumang 1 exploration well was drilled by PMU in December 2003 and the well penetrated gas in a 200m gross interval. Two intervals were production tested with a combined flow rate of 40 MMScf/day. The discovery of Kumang- 1 has open up the prospectivity of similar subtle stratigraphic play in the Central Luconia Province and surrounding areas.
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An Integrated Approach to Develop a Mature Reservoir: A Case History at Guntong 1-10 Infill Drilling, Malay Basin
Authors S.Ch. Hui and M.R. SarifThis paper illustrates an example of integrated multi-disciplinary approach in planning an infill well to drain the oil in the 1-10 reservoir in the Central fault Block of Guntong field. The 1-10 is one of the major reservoirs in the EMEPMI-operated Guntong Field in the Malay basin. The 1-10 consists of low to high energy tidal deposits in the form of subtidal bars and flats. The reservoir is driven mainly by water injection, with occasional gas injection updip. A 3D geologic model has been built and upscaled for simulation in 2001. The well was planned to be a very high angle well that is strata-parallel to the reservoir. The challenge was to stay within 4-5 m from the top of 1-10 for approximately 500 m to target the best part of this reservoir. The main risks associated with the
well were the location of the injected water front, the possibility and extent of gas streaking down through the high permeability layers ane reservoir quality at the heel section of the well. An integrated team consisting of geoscientists, a reservoir engineer and a drilling engineer worked closely to optimise the location and well design. Seismic impedence, AVO respose and time-lapse analysis were integrated with sequence stratigraphy, production performance data and reservoir simulation to finalize the target location and to fully describe this infill opportunity, inculding the associated risks. Several iterations and scenarios were developed to choose the best location to ensure the well is economically robust. A process chart was also developed collectively to lay down the plans while drilling, including fallback actions. Communication among the multi-disciplinary well planning team and the field personnel were also vital in ensuring that all parties were aware of the drilling plans. The well was successfully drilled in May 2004 and encountered oil in 1-10 reservoir with minor gas streaks. Total net completion length is about 400MD and the well flows at about 10000 b/d of oil.
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The Structure and Sequence Stratigraphy of Extensional Basins — A Case Study Offshore Deepwater Sarawak and Sabah
Authors M. Ahmad, H. Mohamad and R. Bischke and J. BoyerA structural and sequence stratigraphy study based on a reprocessed regional grid of 10,000 line kilometers of seismic covering the deepwater portion of offshore Sarawak and northwest Sabah was undertaken with the objective of improving the present understanding of the tectonics, paleo-depositional environments, and overall hydrocarbon potential of the offshore deepwater Sarawak and northwest Sabah Basins. This paper confines itself to a portion of the regional study which consists of the Oligocene to Early Miocene syn-rift section contained within extensional half-graben sub-basins situated beneath a regional Mid-Miocene Unconformity. Several of these haif-grabens exhibit ramp-flat-ramp geometries analogous to the productive Corsair Fault trend! Brazos Ridge Trend, offshore Texas, USA.
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Maturity and Impact of Information Management
By J. KozmanIn order for petroleum exploration activities to progress in the innovative use of the latest technology, and achieve the commendable result of ensuring more discoveries, technology must be underlain by a foundation of effective information management (Nor, 2001). The petroleum industry continues to grow as one of the largest and most intensive creators and consumers of digital data and now recognizes that an organization’s level of maturity in dealing with information and knowledge management can be measured objectively, used as a benchmark to compare with other similar organizations, and provide a proactive plan for increasing performance and profitability. A Data Management Maturity Model (DMMM ) has been proposed as a method of establishing this comparison (D’Angelo and Troy, 2000). The model analyzes organizations as they move from a base level to a fully optimized structure in which data, information, and knowledge add value at all stages in a life of field project cycle. Operations are categorized by analyzing processes, technology, consistency of results, and ability to quantify value.
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Time Lapse Processing for Reservoir Characterization
By Rick WaliaTime Lapse seismic is now becoming a commonly used tool for optimised hydrocarbon field management. Previously, seismic differences were sufficient to be the benchmark to evaluate the 4D signature. Today seismic differences are merely another attribute towards assessing the effect of reservoir production. 4D differencing technology is a highly specific and is based on a full set of generic and specific tools which include surface-consistent matching, 4D stratigraphic inversion, 4D AVO, 4D depth imaging and 4D multi-component processing. The backbone of this technology involves the progressive pre-stack equalization of two or more datasets of different vintages in order to remove the acquisition effects and reveal production-induced differences. Variation of elastic and acoustic parameters, and Poisson Ratio, are typical information that the geoscientists would have better knowledge after having performed the 4D study. The advantage of this methodology is such that even in highly unfavorable conditions of different data vintages, a useful 4D signal can still be extracted. In this paper, we present three case studies coming from different geological and economical environment.
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Growth Methods as a Tool Applied to the Sabah and North Luconia Basins, Offshore Malaysia
Authors R. Bischke, J. Boyer and K. Thies and D. TearpockThis paper presents the Multiple Bischke Plot Analysis (MBPA), and forward modeling balancing techniques as powerful tools to categorize growth in complex structural regimes. The method is based on existing correlations and requires little additional interpretation effort to provide useful results. We have applied this MBPA method as well as forward modeling balancing techniques to a number of faulted structures, which have undergone both extention and compression in the Sabah and North Laconia Basins to determine the relative growth histories.
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Case Study — PETRONAS Applies Robust Evaluation and Analysis in D18 Full-field Review
Authors A.A.B. Zakaria, A.M. Koraini and J. Finolsh and A. RajuSee the work-in progress of a full-field review on one of the most geologically complex fields in Southeast Asia. The Dl 8 Full-Field Review project is a partnership between Petronas Research and Scientific Services (PRSS) and Landmark Consulting & Services. Combining PRSS’ local geology and project management expertise with Landmark’s geoscience and engineering capabilities, this joint team performed a complete reinterpretation of existing data, followed by the development of a sound depositional model based on interpretation of several cores and 3D seismic data. The conclusion? The Dl 8 field is much more complexly faulted than previously conceived, requiring robust evaluation and analysis. The fluid contacts were analyzed and predicted throughout the field, aided by several RFT data points and extensive material balance studies, which also helped reconcile production data, establish STOIIP and determine the main reservoir drive mechanisms. A tentative high-resolution sequence stratigraphy model was developed that is consistent with regional Sarawak geology and stochastic geo-statistical methods were applied to build the static model. Main reservoirs have been located in two progradational units of transgressive systems tract, capped by a regional maximum flooding surface. Geophysical atthbutes analysis coupled with a sound geological model helped in assessing in-place hydrocarbon volumes with possible upside potential for the field. This project is expected to be completed on schedule in December 2004.
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Seismic Frequency Bandwidth Constraints in Deepwater Locations
More LessDeepwater environments typically involve an undercompacted overburden with low quality (Q) factor values (high rates of anelastic attenuation). Rugose water bottom characteristics and complex stratigraphic styles collectively yield surface seismic data that has a small frequency bandwidth and a poor signal-to-noise content. A common misconception associates shallow seismic source and streamer towing depth with increased high frequency amplitudes, larger frequency range, and larger frequency bandwidth (and hence, better vertical resolution). We demonstrate how this misconception arises, and provide a quantitative demonstrate of the true factors affecting frequency content in deepwater data. Noise attenuation is particularly difficult in deepwater areas, as out-of-the-plane (3D) noise generating mechanisms are typically abundant. Standard 2D noise filters are ineffective, thereby degrading an already restricted frequency bandwidth. Consequently, “true” 3D processing algorithms must be applied to remove all noise types. This invokes a critical requirement that the seismic wavefield is densely sampled in both the inline and cross-line shooting directions, and that specific shooting strategies are employed during the 3D acquisition experiment. Overall, we demonstrate how to optimally acquire 3D seismic data in deepwater areas, so that the maximum possible frequency bandwidth, with optimal signal-to-noise ratio, can be both acquired and imaged.
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0-Marine: Advance Seismic Technology for the 21st Century
Authors T. Bruce and J.Z. RashidQ is the Western Geco’suite of advanced seismic services and technologies for enhanced reservoir delineation, characterisation, and monitoring. Q services include proprietary Western Geco acquistion and processing technologies, Q Marine, Q-Seabed, Q-Land, and Well-Driven Seismic. Q-Marine technology was developed after detailed studies to identify the main sources of noise and error that affect seismic data quality. Q-Marine technology has four unique components: caliberated sources, calibrated single sensors, calibrated positioning and steerable streamers. Sophisticated seismic techniques have been the cornerstone of the consistent increase in the E&P industry’s exploration success rate. However, the industry is now looking beyond exploration and applying seismic technology to reservoir management tasks. For these applications, the geophysicist, geologist, and reservoir engineer require exceptional data resolution and imaging quality to understand the subtle and complex details of the reservoir.
A major source of environmental perturbations that affect marine seismic data quality and repeatability is the noise with sufficient spatial weather and sea conditions. Q-Marine records this noise with sufficient spatial fidelity to eliminate it using targeted filtering techniques. Unlike conventional noise suppression, this does not affect the signal bandwidth or fidelity. Q-Marine provides the critical factors needed for enhanced reservoir characterisation and commercially successful 4D surveys. These factors include seismic data with broader frequency bandwidth and higher resolution as well as increased signal-tonoise ratio, which aids geophysicists in attribute analysis. Q-Marine streamers feature the unique QOFin which allows both vertical and horizontal steering of the streamers. Fully calibrated sources, receivers and positioning, in combination with streamer steering, allow QOMarine surveys to achieve a high degree of repeatability compared to conventional acquisition. This has been a critical factor in successful 4D surveys illustrated by a number of recently published case studies. 4D surveys using Q technology have allowed the interval between surveys to be reduced whilst still giving a clear 4D image for accurate and confident interpretation.
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Tanjung Jabung Seismic Project: Key Challenges and Issues in Managing Four Different Seismic Methods in One Project
More LessTanjung Jabung Block seismic project, conducted onshore and offshore of Indonesian Province of Iambi, was one of the challenging seismic survey operations undertaken by Petronas Carigali. Four types of seismic methods, i.e. shallow marine streamer, land, ocean bottom cable dual component (OBC-2C) and transition zone (TZ), were deployed successively. As there were no technically qualified contractors capable of providing services for all four methods, Petronas Carigali decided to split the works into two different seismic survey contractors. While the decision to deploy multi seismic methods was a cost-effective one, it added significant technical, operation and HSE challenges. This paper describes several key challenges, issues and adopted solutions during all the above four different seismic survey methods. As TZ and OBC-2C methods utilized different types of sources and receivers, optimum data overlap was essential for the design of seismic data processing matching filter to correctly merge these two different data types. However, it was challenging task to correctly acquire this required overlap due to shallow water, high daily tide and contractor’s equipment. Harsh working conditions, private cultivated lands, busy shipping lanes, intensive fishing activities, under adaptation of locally sourced boats and lack of contractor’s advance computer QC software were few examples of project key challenges and issues. There were also environmental related challenges and issues where the local authorities prohibited any seismic survey works within the mangrove nature reserve causing no seismic data zone between land and TZ surveys. This no data zone is a challenge for our geophysicist to accurately tie seismic data between land and offshore areas. Additionally there were contract administration and procurement related challenges and issues. It was challenging task to timely administer contracts as there were seven different contracts of various specifications with several contractors. Close onsite project supervision, excellent communication among all parties, thorough project work planning and close interactions with contractor during the operations are several lessons learnt from this project. At the end, the project was successfully completed without any LTI incidents after more than 1.3 millions man-hours were recorded.
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Integrating Sedimentology, Biostratigraphy, Organic Petrology and Petroleum Geochemistry: A Case Study of the Neogene Sequences of Limbang, Sarawak
Authors P. Gou and W.H. AbdullahThis study illustrates the effective utilisation and integration of sedimentology, biostratigraphy, organic petrology and petroleum geochemistry methods on outcrop samples to comprehend the evolution of a depositional basin (sec workflow as given in Figure 3).
The Neogene strata studied here consist of the Setap Shale, Belait and Liang formations, which are located within the Inboard Belt of the Sabah Basin, NW Borneo continental margin (see Figure 1 and Figure 2).
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The Overpressure History of the Malay Basin, Offshore Peninsular Malaysia
By M. MadonThe Malay Basin, located offshore Peninsular Malaysia, is a large Tertiary basin that developed by crustal extensional and strike-slip tectonics. Subsurface pressure data from the central and northern parts of the basin reveal two major overpressure compartments: one in the basin centre and another on the basin flank. In both cases, the overpressure is sealed by laterally extensive, regional shale units. In general, the present-day depth to the top of overpressure has a convex-upward surface; shallower at the centre and gradually deepening towards the flanks. This phenomenon is found to be related to the varying sediment burial rates from basin centre to flanks; a higher sedimentfburial rate produces a shallower top of overpressure. In detail, however, the present-day depth to top of overpressure is also influenced by the presence of regional shale seals. In the basin centre, the top of overpressure is generally between 1900 and 2000 m depth and is limited stratigraphically to within the lower part of seismo-stratigraphic unit or “group” E. The top of overpressure is shallower towards the basin flanks, and is less than 1500 m deep along the faulted, western basin margin. It appears that the top of overpressure in the basin centre is influenced by the Group F shale, and that the overpressure in lower Group E down to Group F represents the overpressure transition zone. Modelling studies indicate that overpressure had developed very early, during the synrift phase (ca. 30-2 1 Ma), when sediment burial rates were very high (>1000 rn/Ma). The overpressure developed during this “build-up” phase, however, has been dissipating gradually since the post-rift phase began 21 Ma ago, when burial rates were reduced considerably below 1000 rn/Ma. This indicates that disequilibrium compaction, resulting from high sediment burial rates, was effective only during the synrift phase of basin development. Low sediment burial rates during the post-rift phase (generally less than 500 rn/Ma) are not enough for overpressure to develop. Hence, the overpressure in the post-rift strata, as observed at the presentday, appears to be of secondary origin, derived from the excess pressure in the underlying synrift strata. The present-day distribution of overpressure in the basin, therefore, is not a primary feature, but is due to pressure dissipation and re-distribution during the post-rift phase of basin evolution.
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Measurement of Sediment Surface Heat Flow and its Application in Deepwater Exploration
Authors B.B. Bernard and J.M. BrooksA tremendous amount of heat is constantly transported from the earth’s center to the surface by thermal convection and conduction. A portion of the heat conducted through the earth’s crust is used to drive the chemical reactions that transform sedimentary organic matter into petroleum. At any point in the sediment column, the conductive heat flow is the product of the temperature gradient and thermal conductivity. Heat flow (Q), measured in mW/rn2, is determined by multiplying the site thermal conductivity (k), measured in W/m-K, with the geothermal gradient (G), measured in mKJm, and determined from the thermistors. Accurately measuring this heat and understanding its transport mechanisms through the crustal rocks are essential to the science of deepwater petroleum exploration. The thermal history of deepwater sedimentary basins is of great interest to petroleum geologists because the hydrocarbon maturation process is controlled primarily by the temperature the source rock has experienced since its deposition. Researchers mathematically constrain the sedimentary thermal history by building a physical model that simulates the processes whereby the sediments become gradually heated by geothermal heat as they are deposited, buried, and compacted over time. The researcher must have detailed knowledge of the sedimentation history, the thermal properties of the sediments, and the regional geothermal heat flux in order to reconstruct the thermal history of the basin of interest.
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Thin Oil Development in Semangkok E-20 Reservoir, Malay Basin
Authors F. Rokhani, M.N. Ismail and D.A. RahmanThe Semangkok Field, located offshore Peninsular Malaysia was first discovered in 1981 and developed in 1984 by two platforms, Semangkok A and B through 41 development wells. Subsequent to the initial field development, EMEPMI has conducted several re-developments at Semangkok, including the Semangkok B infill drilling program in 2001, and Semangkok A infill drilling program in 2003. This paper addresses the challenges involved in the re-development of one such reservoir, the E-20, which has a relatively
thin (—1 2m) oil column at Semangkok. The E-20 reservoir, with its —12 m crestal oil column, small gas cap and strong bottom water drive, was considered uneconomic during the initial development. Three wells were completed in this reservoir as a secondary objective during the initial development, with only one well making reasonable cumulative production of 0.5 MBO, while the other two wells saw early water breakthrough. All of the wells had relatively long perforation intervals, with the higher cumulative well having a coal layer close to the base of perforation which potentially acted as a buffer to prevent early water encroachment. In 2002, an idle well was worked-over to add perforation in the E-20 reservoir. The perforated interval was only 1m TVD at the mid oil column, to provide sufficient stand-off from the interpreted current OWC and help reduce early water breakthrough. This well produced at a sustainable rate of 0.8 kbd with low GOR and watercut, and based on the encouraging performance, two additional single horizontal oil producing well targets were recognized for future development. Key challenges for these targets included the optimal placement of the horizontal section to minimize water coning and maximize productivity of the thin oil column. As such, risks for these wells included structural and stratigraphic uncertainties and the possibility of early water breakthrough. This paper discusses ways the integrated team took to optimally address these challenges and maximize production.
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Exploration : Catching the Next Wave
By W. HoogeveenThe oil and gas industry, and in particular, exploration, is challenged to continuously deliver new volumes in a world where heartlands are getting tired and the big finds are becoming increasingly difficult to make. The industry’s exploration efficiency is driving us towards smaller and, in many cases, more remote, accumulations. But there are still ample resources yet to be discovered. Knowing where the hydrocarbons are, however, is not enough. If we apply the filters of “Accessibility” and “Profitability” we are left with what we call the “new battlegrounds” for exploration. These are the backdrops against which the oil and gas industry will have to operate to fuel the energy demand. In Shell, we have taken stock of where we are and where we want to be to rise to the challenge. Shell’s strategic thrust is to have more upstream and profitable downstream. The bulk of our investment will be in upstream exploration, production and gas supply business. Our exploration strategy has evolved from a focus on asset-driven near field exploration and a very large global spread, to shifting our focus to more material exploration opportunities, in fewer countries and in choice basins. With increased focus on material opportunities, emerging plays, and fostering core knowledge and skills, we believe we
are poised to catch the next wave of success through partnership with others. The “new battleground” pushes us to go deeper, be faster and cheaper. As a global leader in Deepwater exploration and development, we have the people, we have the technological edge and we also have the commitment backed by our track record and successes.
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The Allocation of Exploration Dollars in a High Oil Price Environment
By P. EbdaleThe high oil prices of the late 70’s resulted in exploration investment trends in the 80’s that destroyed value for the industry. The oil price is rising again and many are suggesting that the industry may be operating in an environment where oil is priced in excess of $ 30 a barrel for a significant period of time. Will we learn from the mistakes of the past? The complex question of the allocation of exploration dollars across an international portfolio involves the convolution of many factors; economics, company strategy and the ability to secure quality acreage, to name but a few. By simplifying the question to two geographic/geologic provinces, namely the deepwater Gulf of Mexico and South East Asia, an analysis of the key decision criteria can be conducted, these can then be compared and contrasted while referencing against a prognosed high oil price. Does the exploration investment climate favour the United States over SE Asia? If so why, and will history repeat itself?
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Remote Detection of Hydrocarbon Microseepage: An Alternative Exploration Tool For Onshore Exploration
By M.R.Ch. KobMicroseepage is a common phenomenon (Saunders et al., 1999) and more than 85 % of known oil and gas fields show some degree of hydrocarbon microsepage (Richer, 1982). This microseepage is associated with hydrocarbon accumulation below the surfaces, causing detectable anomalies on the surface. And these surface manifestations of hydrocarbon accumulations has long been studied and documented through surface analyses such as geochemical, Geophysical, geomorphological studies and etc.
The association of hydrocarbon induced surface anomalies with the tonal anomalies as seen on the satellite images has been studied quantitatively and documented. It has also been used to explain the distribution of the hydrocarbon microseepage in the producing basins, such as Tucano basin in Brazil. Successful prospecting using surface studies and remote sensing has increased globally. It has been documented in the USA, Libya, Caspian Sea region, Brazil and China with high success ratio compared to when only conventional methods are applied. The prospecting method using surface studies and remote sensing are comparatively cheaper and faster than the conventional seismic method. It also enables a wider search area and more cost-effective. It also supplements the conventional methods by providing surface “DHI’ s”, which can remarkably reduce uncertainties and risk, and subsequently increase the success rate in exploration. The current advances in remote sensing imaging and digital image processing provide plenty and vital information on hydrocarbon below the surface, if it is properly calibrated and applied.
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Gas Hydrates in Seabed Sediments, Offshore Trinidad/Barbados
Authors B.B. Bernard, J.M. Brooks and N. Summer and S. FlanaganMany of the discoveries and studies of gas hydrates in shallow seafloor sediments in the Gulf of Mexico and West Africa have resulted from Surface Geochemical Exploration (SGE) coring studies conducted by the authors. In the present study, we provide new information on the distribution, occurrence, and chemical nature of gas hydrates offshore Trinidad and Barbados.
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Coal Depositional Settings of Mukah-Balingian, Sarawak: Implications for Coaly Petroleum Source Rocks of the Balingian Province
Authors Ch.S. Ni and W.H. AbdullahThe coals and coaly sediments analysed in this study are from the Neogene (Miocene-Pliocene~ coal-bearing sequences of the Begrih-Liang and Balingian formations which outcrop within the onshore part of the Balingian Province. Most of the samples analysed are from the Sulau Coal Quarry and outcrops along the Mukah-Selangau Road. Using a combination of lithofacies studies, organic petrological analyses, and organic geochemical characteristics of these coal-bearing sediments, the environment of deposition for both the Balingian Formation and the Begrih-Liang Formation appears to have been within fluvial-deltaic. However, there seems to have been greater marine influence in the Begrih-Liang Formation compared to the Balingian Formation. Although most of the coals studied are of an autochthonous origin (formed beneath the plant cover from which they were derived), some are hypautochthonous deposits (originated from material that was transported from its immediate source but accumulated within the same sedimentary environment). The autochthonous coal deposits are relatively thicker and commonly associated with rootlets within the underlying clay while the hypautochthonous coal deposits are relatively thin and associated with significant amounts of clay minerals.
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Chasing Subtle Plays in a Mature Carbonate Province
Authors P. Lambregts, G. Jaeger and D. Sim and S. GuestThe Central Luconia Province is a stable Late Tertiary platform, flanked by two area’s of active deltaic sedimentation, located offshore Sarawak. It is characterised by widespread carbonate deposition, which started in the Early Miocene, and during Middle to Late Miocene high-relief carbonate build-ups developed with some reaching a thickness of more than 1500m. This carbonate depositional phase ended with a series of regressive events, and the build-ups became subsequently covered by marine shales derived from prograding deltas. These high relief carbonates formed the historic exploration objective since the mid- 1960’s, with some 40 Tscf reserves discovered to date. This play, which was evaluated on 2D data, is well understood and very mature. The success rate of this play has been decreasing, culminating in a 5 well drilling campaign in 2000, without a commercial success. The play appeared creamed with limited volume potential left. The advent of larger production-oriented 3D surveys provided new insights into the early phases of carbonate growth and allowed the identification of subtle traps adjacent to the prolific discoveries. Making use of constrained sparse spike inversion a porosity sweetspot, encased in a potential low permeable facies, was identified near the large Eli Field. This was subsequently drilled as a secondary objective of a deeper test. The result of this well proved that a sealing tight carbonate facies is present as the GWC extends 250 ft below the structural closure, making this discovery a true stratigraphic trap. This discovery has resulted in a different way of looking at carbonates, moving away from high relief 2D structural evaluation towards subtle, 3D based, facies mapping. Several other low relief build-ups have been identified since on 2D and
late 2003 the first exploration 3D has been acquired to mature this play further.
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Applying GIS Tools to Focus Exploration in NW Borneo — A Timely Catalyst for Consolidation
Authors A. Chan, N. Wong and P. Kelly and R. KnightFor decades, NW Borneo has, and continues to prove a high value hydrocarbon province to Shell. Although there has been a shift in focus in recent time, away from the conventional shelfal plays towards the highly successful deepwater acreage, the volume and hence the challenge remains for exploration to maximise any remaining potential in the Inboard area. Under this remit, regional geology is critically underpinning Shell’s evaluations in this area, and ArcGIS proving an excellent platform for the compilation, manipulation, and analysis of data, derived from a wealth of sources: the power of GIS is that it allows the quick assimilation of information, from a diversity of projection systems, into one unified view. Although utilised for many years by non-Petroleum companies, the value-adding potential of GIS has only recently been recognised by the Oil Industry, with Shell one of the forerunners in it’s subsurface application. The eloquence of this tool is in allowing the individual to control the type and style of data to be imported and rationalised: data configuration tends to be rapid, with the search facilities ideal for creaming-off and spatially visualising any single element from complex and often huge databases. Seismic, well, geophysical, geological, geochemical, play, engineering, production, commercial, or portfolio data can be compiled, decimated, screened and efficiently re-assembled in a seemingly limitless number of permutations by the user. Your own creativity is the limitation. Links to Openworks and a spectrum of in-house corporate databases is allowing a wealth of information, traditionally remote to the GIS environment (e.g. interpreted horizons) and often the user (!), to be quickly incorporated in any evolving project work. One of the key benefits of ArcGIS to SSB Exploration has been the rejuvenation and compilation of strategic play maps, by allowing rapid data screening, and providing amongst others a medium for corporate memory capture and simple documentcopy management. A diversity of data including structural maps, play success rates, gross depositional facies belts, charge domains, rock property data, and hydrocarbon quality information is being assimilated, allowing pan-shelfal prospect maturation activities to be placed in a more coherent framework.
Simply, ArcGIS is an incredibly fast, nimble and thought-provoking tool, which should form an integral part of any Exploration (& Production) outfit, when tackling the uncertainties of the subsurface.
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Phu Khanh Basin, a Frontier Deepwater Basin in Vietnam
By P. ChungkhaThe Phu Khanh Basin is a north to south elongated, approximately 300km long and 100km wide, extensional basin. It lies in approximately 20-2,500m of water in the Vietnam continental shelf area, which comprises a series of Cenozoic sedimentary basins, located within a transitional zone from the continental crust of the Indochina Craton to the oceanic crust of the South China Sea. The Phu Khanh Basin is bounded to the north by the north-east to south-west trending Da Nang Shear Zone, on the east by the steep continental slope of the South China Sea, on the west by the Da Nang Shelf and is separated from the Cuu Long Basin to the south by the north-west to south-east trending Tuy Hoa Shear Zone.
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PETRONAS Visualisation Centre (PViC)
Authors F.S. Jamean and Z.M. NorLocated on the 22nd Floor, Tower 2, PETRONAS Twin Towers, PETRONAS Visualisation Centre is a state-of-the-art advanced visualisation facility aimed for use by PETRONAS, PSC Partners and partner suppliers. The centre is equipped with sophisticated infrastructure and multi vendor visualisation software to facilitate collaboration sessions for prospect selection and viewing well location picking, well planning sessions and facilties design reviews, among others. Built in a record period of four months, the centre was officiated by PETRONAS President and CEO, YBhg Tan Sri Dato Sri Hassan Marican on 18 August,2004 with the audiences of internal guests and key personnel from PS contractors in Malaysia. Being the first of its kind in PETRONAS, the centre was built to provide PETRONAS and E&P companies in Malaysia with access to a highly visual, three-dimensional environment which will allow technical personnel to collaborate and create additional values from their activities in exploration, development and production of hydrocarbon resources. The centre is powered by SGI Onyx35O Computing System with two 1R4 graphics pipe for high quality visualisation. Three 6000 lumens rear projected projectors with curved screen provides brighter image and quieter working environment. The centre is also equipped with active and passive stereo setup which gives immersive effect. PViC is a multi software and multi vendor centre which allows E&P people from various fields to gain advantage from utilising the centre.
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Geothermal Resources Potential in Apas Kin, Sabah
By K.B. HassanThe geothermal investigations of the Tawau-Semporna area, in the state of Sabah, have been discussed by many workers, who include Lim (1988); Sanudin et al., (1990); Lim et al., (1991); Tjia et al., (1992); Liau (2001); Takashima et al (2001); Ang
(2002); Lim and Takahashi (2003), Takashima et al (2003), Kamaludin (2004), Javino et al (2004) and others. The earlier works, mainly done during the 80’s, had investigated on the surface water chemistry, aerial photo interpretation and limited petrographical, structural analysis and geophysical surveys. Starting after 2000, interests on the prospects of geothermal resources of the Tawau-Semporna area were revived. Follow-up investigations, even though piecemeal, have accumulated encouraging data. The TL dates, determined by Takashima et al (2001, 2002, 2003), have added to alternative interpretations on the age sequence of the rock formations in the area. The isotope and geochemical water sampling carried out in 2003-2004 have shed further lights on the thermal water properties of the area (Javino et al, 2004). The Apas Kin area shows the best resources potential among the Tawau-Semporna geothermal manifestations. The chemical geothennometers of Na-K-Mg show reservoir temperatures ranging 180-210°C. Meanwhile the isotopic geothermometers ~O (S04-H20) estimated the reservoir temperatures ranging 152-196°C. The geothermal potential of the Apas Kin area is recommended best harnessed for electricity generation. Even though geothermal power generation is a new ‘thing’ for Malaysia, it has in fact benefited many countries over the world since the 70’s. It has the advantages in that it’s a clean fuel (what is emitted is just steam-or plain water), thus very environmentally friendly, reliable power generation, cheaper electricity production costs in the long run, require less land area for geothermal power plant and many others. Conforming to Malaysia’s policy on renewable energy and the promoting for a more environmental healthy power source, it is thus recommended that the Apas Kin geothermal resources be tapped and harnessed accordingly.
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Rock & Fluid Acoustic Models Inboard Sabah in Support of Seismic Amplitude Calibration Studies
Authors R. Ngu, S. Dolan, T. Johnson and Ch.-H. Hoo and F. HoCalibration of seismic amplitude response requires accurate models of the acoustic properties of sands, their bounding shales, and pore fluids at varying conditions of pressure, temperature and depth of burial. Such models are constructed from careful, rigorous and integrated analysis of geological, petrophysical (LWD/wire-line & core data) and seismic data. Progress in describing and modeling the acoustic properties of sandstone reservoirs, their bounding shales and pore fluids in Inboard Sabah area will be summarized in this poster. The fundamental workflows of building rock and fluid model that has been developed are: Edit and QC well logs against the core data. Perform basic petrophysical evaluation (Fig 1). • Establish fluid property model via laboratory measurements (PVTsim), and mineral property model via petrology studies (XRD analysis). • With the fluid property model, correct the bulk density log for invasion. With fluid and mineral property models, perform Gassmann Substitution for hydrocarbon-saturated intervals to 100% brine. Perform event-extraction on log properties and derive rock property model (Fig 2 & 3). Perform seismic amplitude calibration studies. The plan is to constrain each field in the Inboard Sabah area by a set of high-quality rock and fluid property relationships, which are used for pre-drill prediction of reservoir quality in neighbouring exploration prospects.
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Inversion of a 3D Seismic Dataset Offshore Sarawak: F23 Case Study
Authors J. Majain and A. NadadaserThe F23 field lies in Sarawak waters within Block SK-308, some 150 km offshore Sarawak. F23 is an isolated, platformtype Miocene (Tortonian-Messinian) carbonate build-up. The original depositional texture controls to a large extent the pore types and therefore the porosity/permeability character of the various lithofacies in F23. The large variability seen in porosity! permeability character within a specific lithofacies is related to textural variations associated with depositional cyclicity. The distribution of the porosity/permeability within the carbonate build-up will affect the development strategy of F23. A seismic inversion project was therefore carried out on the F23 field with the following objectives: - To generate an acoustic impedance dataset suitable for stratigraphic interpretation which was used to fine-tune the structural interpretation of the build-up - To generate a porosity volume for analysis for the porosity! permeability trend to assist in the design of the future development wells The Jason CSSI inversion was carried out attempting to meet the above-mentioned objectives. The data used were a full stack seismic volume, well logs from ten wells, five seismic horizons and a seismic velocity volume The essential processes in the project consist of seismic-to-well ties, wavelet estimation, construction of earthmodel and finally the generation of the acoustic impedance data. Based on the cross-plot of the inverted P-impedance and well porosities, a regression curve was derived for the conversion of the inverted P-impedance volume to the porosity volume. The refined structural interpretation based on the inverted P-impedance seismic and the porosity volumes were subsequently exported to Petrel for the building of structural framework and for the property modelling for the F23 static model. The current poster will show the seismic inversion workflow and the results of the F23 seismic inversion project.
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Acoustic Impedence Inversion and AVO Analysis of Pre-SDM versus Pre-STM Data
Authors A. Duen-Woei and Ch.E. Harris and L.H. KuangBoth Guntong and Irong Barat fields are located off the East Coast of Peninsular Malaysia in the southeastern part of the Malay Basin. EMEPMI acquired the most recent 3-D seismic over the hong Barat and Guntong field in 1998. These data were processed through Pre-Stacked Time Migration (Pre-STM) and subsequently re-processed through Pre-Stacked Depth Migration (Pre-SDM), in 2001 and 2002 respectively, in order to address remaining imaging issues assocaited with faults and continuity below shallow gas. EMEPMI Geophysical Application group analyzed the Ore Stack Depth Migrated (Pre-SDM) data over these two fields to determine whether these datasets were suitable for reservoir characterization. The results were compared to the equivalent analysis using Pre-Stack-Time-Migrated (Pre-STM) data. Pre-Stack AVO and Post-Stack amplitude analysis was performed over the Irong Barat C (TB-C) development area to confirm the robustness of the Pre-SDM amplitude observations for the H20 reservoir. Acoustic impedance inversion was performed over the Guntong field for both the Pre-SDM and Pre-STM datasets. The results from both field studies indicate that the Pre-STM and Pre-SDM data are in general agreement. However, the Pre-SDM data seems to have a more consistent and geologically meaningful amplitude response than that of the Pre-STM data. The result of AVO analysis over Irong Barat was subsequently used in the DHI risking analysis and as partial justifiaction for full funding of the TB-C development. The Pre-SDM acoustic impedance (Al) inversion volume over Guntong is currently being interpreted.
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4D Feasibility Study in Carbonate Field for Reservoir Management
Authors Ch. Odukwe, K.Y. Cheong, H. Zhu and J. Ngu and M. LawsonThe use of the 4D seismic method for reservoir management has been well known in the Oil Industry for a number of years. The method provides a geophysical measurement of fluid and rock property changes during the lifecycle of a producing field and allows cost effective and timely reservoir management decisions. Most of the success stories from 4D work in the past have been in clastic reservoirs where the seismic response to production is greater than in carbonates. A 4D seismic study on a carbonate field in the region has shown to be successful in imaging a GWC rise and this has led to increased confidence in the use of 4D for other carbonate fields. M4 is a newly developed carbonate gas field with oil rim that came on stream in 2002. The field is a reefal fiat top
carbonate built-up. It is developed with two sub-sea horizontal wells located at the top of the structural high. There is no other observation well for reservoir dynamic behavior monitoring. It is therefore critical to know the GWC movement in establishing the security of supply from this reservoir and to put in place mitigating measure as earlier as possible. A 4D seismic survey is planned for the field in 2005/2006. This feasibility study was carried out to provide support for the planned 4D seismic survey with the objective of 1) Assessing whether a 4D signal could be detected and 2) Predicting the best time for the Monitor survey. The workflow and findings of the 4D feasibility study will be outlined in the Poster.
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Angsi Field —World’s Largest Platform Based Fracturing Operations
Authors M.A. Ismail and H.M. NoorThe Angsi field is the largest integrated oil and gas development in the region and the first tight gas development in Malaysia. Itis located 165km off the East Coast of Peninsular Malaysia in a water depth of 70m. Angsi Project is a joint venture between PETRONAS Carigali Sdn Bhd ( PCSB ) and ExxonMobil Exploration and Production Malaysia Inc. EMEPMI), operated by PCSB. A dedicated project management team consists of technical personnel from PCSB and EMEPMI was formed to oversee the timely and prudent development of the field.
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Awakening Barton: Multiple Scenario Modelling
Authors K. Hedeir and F. Kandau and A. WidjiastonoThe Barton Field is one of the mature oil fields in SM-EP located offshore Sabah, approximately 220-km northeast of Labuan Island with a water depth of 130 ft. The 3 main reservoirs (G, H, and I) are developed from two mini platforms and a total of 13 producing wells. Barton has been producing with gas lift under natural depletion since April 1982 (20 years of production) with a drive mechanism governed by good gravity segregation and moderate aquifer support. The reservoir pressure from this primary depletion development has decreased from 1058 psi to 550 psi. The reservoir characteristics of the field, and its current condition as a mature, relatively low-pressure field, make it a suitable candidate for a secondary recoveiy project through pressure maintenance, provided the subsurface complexities are well understood. Subsequently, an integrated modeling exercise, through building of multiple geologic realisations, was launched to assess which of the pressure maintenance options, such as gas injection, hybrid gas and water injection and water injection, would give the best results in terms of recoverable reserves and associated economics. An opportunity framing exercise has identified two groups of uncertainties in the form of structural (structural interpretations
and quantifications, fault identifications and sealing capacity) and resevoir geological (facies identifications, correlations, sandbody geometry and orientation) uncertainties. These key uncertainties are mapped and captured systematically in a series of 3D realisations and modeling workflow. Integration of the latest results from cores, biostratigraphy, seismic, juxtaposition plot, bubble-plot, and pressure data as well as analogues formed a sound technical basis for the current modeling. Five out of a total of twenty-two realisations were successfully history-matched. The results thus used for the basis for evaluating developments options, of which water injection is identified to be the most optimal. The first well of Phase 1 of the 2-phase Barton Filtered Minimal Seawater (BTFMS) project will be drilled in Q4 2004. Good and constant communication between team members and geologists in a ‘ring-fenced’ environment as well as the availability of a powerful 3D modelling tool (PETREL) are parts of the enabling factors to the success of the study. This study is an example of how multi-disciplinary integrated approached helps in proper handling of uncertainties, which leads to a robust field development plan.
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Petroleum Systems of the North Malay Basin
Authors M. Madon, P. Abolins, R.A. Hassan, A.M. Yakzan and J.-S. Yang and S.B. ZainalThe North Malay Basin comprises a 100 km-wide centrallbasinal gas-prone area, flanked on both sides and to the south by mixed oillgas zones. Non-associated gas fields in the central zone (Cakerawala to Bujang Trend) are reservoired mainly in groups D and E, in anticlinal traps formed by basin inversion during late Miocene times. This distribution may be biased by the depth of well penetrations in the basin centre due to the onset of overpressure. Oil occurs in faulted traps along the Western Hinge Fault Zone (Kapal to Beranang Trend), and is especially abundant on the NE ramp margin (Bunga Pakma-Raya Trend) where a separate kitchen may be present. Oil geochemistry reveals three main sources for the oils: lower coastal plain, fluvial marine and lacustrmne source rocks. Most of the oils and condensates in the basin centre and on the Western Hinge Fault Zone are lower coastal plain oils, indicating charge from the basin centre. Lacustrine oils are restricted to the Bunga Pakma-Raya Trend on the NE flank,
indicating charge from the basin centre as well as input from a small sub-basin to the northeast. Marine influence was found in oils from the most central position in the basin (Cakerawala-Bumi area). Vitrinite reflectance and basin modelling indicate that hydrocarbons were generated from source rocks within two main stratigraphic intervals: Group H and Group I, which are presently in the peak oil generation and gas generation stages, respectively. Figure 1 shows the distribution of oil and gas fields in relation to present-day groups H and I maturity.
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