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PGCE 2011
- Conference date: 07 Mar 2011 - 08 Mar 2011
- Location: Kuala Lumpur, Malaysia
- Published: 03 July 2011
21 - 40 of 104 results
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Fabric Anomaly in Mud Clast Distribution in the Lambir Formation (Mid to Late Miocene), Sarawak.
Authors E. Padmanabhan and A.S. Mohd PauziThere is an increasing interest in the anisotropy of mudstone systems mainly due to seismic anisotropy caused by change in wave velocity and polarization with propagation direction. Therefore, the study was to evaluate the variability in the mud clast distribution in the heterolithic sequences present in the Lambir Formation. Mud clasts show differences in size, shape, thickness, continuity and orientation with respect to the general bedding attitude. The clasts are generally ellipsoidal in shape despite some of them being subrounded. It is evident that the amount of energy needed to transport the larger mud clasts was more than that needed to transport the finer sand grains. The origin of mud clasts remains debatable as the energy setting in which it occurs is generally not in favor of the stability of this feature. Results suggest that size variation of mud clasts with increasing distance from the base could be quite erratic in some places despite a general trend of fining upwards. We introduce the term “fabric anomaly” to describe this feature. The Lambir Formation has tremendous variability at various scales of observation. The fabric anomaly exhibited by mud clasts has the potential to impact critical properties of the clastics.
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An Overview of the Proven Pre-Tertiary Karstified and Fractured Carbonate Basement Play-Type in the Offshore Northern Vietnam
Over the past 6 years, PETRONAS Carigali Overseas Sdn Bhd (PETRONAS), through its exploration arm in Vietnam, has explored for the hydrocarbon potential of the Pre-Tertiary karstified and fractured carbonate Basement play-type in offshore northern Vietnam (Figure 1). The first encounter of this play type in the subsurface offshore northern Vietnam was in 2004 when severe mud losses were experienced when the A-1X exploration well penetrated ‘caves’ in the carbonate Basement. Since then, effort was intensified and further technical analysis was carried out until PETRONAS successfully made a commercial discovery in the “D” structure through the D-2X exploration/appraisal well drilled earlier this year. This milestone discovery has proven the prospectivity of the Pre-Tertiary karstified and fractured carbonate Basement play-type, the first of its kind in the offshore northern Vietnam. The reservoir penetrated consists of limestone and dolomitic limestone, which can be closely analogue to the similar carbonate formation exposed as ‘islands’ at Ha Long Bay (Figure 2), located some 100km to the North-Northeast from the discovery. This Carboniferous-Middle Permian dolomitic limestone, interbedded with oolitic limestone and calcaro-cherty shale is referred to as the
Bac Son Formation (C-P2), which is about 1000m thick, monoclinal and undulatedly folded, containing foraminifera beds from Chernyshinella, Dainella, etc. to Cancellina, Neoschwagerina, Werbeekina beds gathered with remains of crinoids, brachiopods, bivalves, bryozoa, etc. and corals, conodonts, radiolarians etc. (Tran Van Tri, et al., 2003). Apart from the cavern system evidence from the outcrop in Ha Long Bay (Figure 3), the carbonate karst-hill and tower karst structures are also fractured, similar to the results from the wells drilled into the Pre-Tertiary carbonate. These faults and fracture sets are believed to have contributed to the increased secondary porosities and permeabilities by acting as the reservoir conduits that connect to the cavern system and matrix (Nelson, 2001). According to Jamin, et al, 2009, successful hydrocarbon exploration in such play-type offshore northern Vietnam is attributed to a working petroleum system defined by the interplay of the following factors: i) presence of porosities and voids in the carbonate reservoir; ii) increased permeability due to the presence of faults and fractures; iii) presence of a thick and mature lacustrine shaly section which acts both as a source rock and top and lateral seal; and iv) structural formation (Pre-Tertiary) predating oil expulsion and migration. Oil expulsion and migration from this lacustrine source rock began during early-mid Miocene. The biggest uncertainties and challenges arise from the poor to marginal quality of the current seismic data at the reservoir level which puts a limitation on accurate fractures/lineament and cavern mapping and prediction and also on mapping the base of the carbonate. A much better data quality and more advanced techniques might help to reduce these associated uncertainties.
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Mapping Regional Sedimentary Horizons in the Onshore Baram Delta, Sarawak, from Magnetic and Graviti Data Using Energy Spectral Analysis
Aeromagnetic and airborne gravity data acquired over the onshore Baram Delta, Sarawak, Malaysia, was used to estimate depth to economic basement that is the Top Cretaceous (Horizon-1), and depth to three intra-sedimentary horizons: Top and Base of Carbonates (Horizon-2 and Horizon- 3), and the top of an additional shallower interface (Horizon-4). Depths to these horizons were calculated through the analysis of energy spectra of the observed magnetic and gravity fields, while faults and magnetic lineaments were derived through the application of an automatic curve matching (ACM) method based on the Naudy technique. The project involved the application of a new spectral technique, termed the Multi-Window- Test (MWT). The application of the MWT allowed quick estimation of depth to multiple horizons (skeleton maps) and also provided a set of optimal window sizes used for detailed mapping. The potential field derived results correlate well with both seismic and well data. Spectral methods have been successfully applied in the study area, and the MWT has proved itself a valuable tool in producing a robust interpretation of potential field data.
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Efficiency of TDEM and EM-IP Methods Application for Reservoirs Exploration in South East Asia
Application of electromagnetic methods for oil and gas exploration is developing world-wide. Two main types of EM methods are applied: natural source (MT) and methods with artificial source of EM field (TDEM, FDEM) [2]. For hydrocarbon exploration on land high efficiency has transient electromagnetic method in frequency or time domain mode. The role of EM methods is increasing at the areas with poor seismic data quality, non-structural fields and zones with complicated structure of sedimentary cover. Joint interpretation of EM data with seismic or other geological data is a way to reduce the risks and optimize the process of geophysical investigation. For oil and gas exploration it is possible to study sedimentary layers resistivity at the depth interval from surface to basement and also a lot of information can be received from induced polarization (IP) parameters. The paper is devoted to technique of EM methods combination – TEM and EM-IP for oil and gas exploration, and possible ways of its effective application. Forward modeling results for geoelectric models are shown.
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Rotation of Borneo Revisited – New Inferences from Gravity Data and Plate Reconstructions
Authors Stan Mazur, Christopher Green, Matthew Stewart, Rkia Bouatmani and Paul MarkwickBorneo has commonly been considered to have undergone two stages of major anti-clockwise rigid-block plate rotation - 50° between 80 and 30 Ma and 40° between 30 and 10 Ma (e.g. Fuller et al., (1999) and Hall (2002), based on interpretations of palaeomagnetic data from Kalimantan and Sarawak). These interpretations have recently been challenged (Cullen, 2010). Considerations based on gravity data and plate modelling add further concerns. Cullen (2010) pointed out that the earlier authors had rejected those palaeomagnetic data that did not match their model, using the argument of young re-magnetisation. If those data are taken into account, the 30-10 Ma anti-clockwise rotation must have been restricted to smaller tectonic blocks, with no rigid-plate rotation of Borneo as a whole. It should also be noted that the palaeomagnetic data from Borneo provide similar results to those for the Malay Peninsula, Sulawesi, the Celebes Sea and parts of the Philippines; this suggests that any rotation should be applied to a block much larger in extent than just Borneo (Fuller et al., 1999).
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Determination of Avo Attributes for Hydrocarbon Resources Region of Malay Basin: the Fluid Factors
Authors T.L. Goh., Uzir Alimat, Shaidin Arshad and M. Izzuljad Ahmad FuadFluid factor is one of the most important AVO attributes in seismic for reservoir hydrocarbon prediction. The typical published fluid factor, F =1.252A+0.580B was derived based on Castagna’s mudrock equation (Castagna et al. 1985), Vp=1.16Vs+1360 and Gardner’s relation (Gardner el al.1974), =0.23Vp0.25 and was developed based on brine saturated siliciclastics data obtained from Gulf of Mexico. These are true as hydrocarbon indicator for reservoirs of Gulf of Mexico. Since the geological settings for Malay basin are different with Gulf of Mexico, therefore the determination of fluid factor for Malay Basin is very crucial. The respective values of A and B were the intercept and the gradient attribute of reflection amplitude versus sin2 plot. Castagna and Smith (1994) reported that the respective value of fluid factors for background (nonpay) and shale/gas-sand interfaces are zero and negative. In this paper, the fluid factor equations based on local mud rock equations as outlined in Table 1 (Vp versus Vs and density versus Vp plot), which were obtained from brine saturated siliciclastics data of 48 wells, were established for respective six petroleum resources regions, Malay Basin. The six petroleum resources regions as illustrated in Figure 1 were divided based on geographical locations and play types, namely region 1 - North Malay Region; region 2 - West Malay Region; region 3 - South Malay Region; region 4 - Southeast Malay Region; region 5 - Northeast Malay Region and region 6 - Central Malay Region. The rock physical trend lines for region 1, 2, 3, 4, 5 and 6 were established based on 7, 3, 7, 5, 14 and 12 wells data respectively. The respective fluid factor equations for six petroleum resources region 1, 2, 3, 4, 5 and 6 were F=1.235A+0.568B, F=1.219A+0.563B, F=1.238A+0.586B, F=1.222A+0.608B, F=1.228A+0.573B and F=1.263A+0.536B.
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Soft Shale Complication in Avo Interpretation in Sabah Basin
Authors Alex Tarang and Yeshpal SinghField A is a faulted EW trending anticline which has been produced for more than two decades from early Miocene sand. It is very important to understand the rock elastic properties for the purpose of near field wildcat exploration. In Field A, the shale which capped sands is called ‘A’ shale and roughly 70-100m thick across the field. The upper part of the ‘A’ shale has Acoustic Impedance(AI) higher than that of the shale, however, the lower portion of the shale is the opposite. Therefore, such a response imposed a challenge to differentiate the sand and shale responses on seismic data set. Detailed rock physics modeling on petrophysically conditioned logs is a must in order to quantify the elastic properties of the shales with reference to underlying sand reservoir. Figure 1 shows the representative well log response and histograms for shales and sand. Our analysis revealed that soft shale seismic amplitude response is similar to that of the gas sand. The proper AVO/rock physics modeling of the soft and hard shale and the various fluid fill sands responses are necessary in order for us to do correct AVO analysis and thus to be used correctly in the prospect de-risking process. It has been observed that elastic properties like Elastic Impedances, LambdaRho-MuRho are necessary in order to distinguish among them. In addition, proper conditioning of the pre-stack gather is also necessary in order to improve the data quality and enhance the subtle contrast.
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An Integrated Approach to Reservoir Appraisal and Monitoring Using Well Log, Seismic and CSEM Data.
Authors Lucy MacGregor, James Tomlinson and Skander HiliThe controlled source EM method has developed into a tool that is often used in de-risking the exploration process. In this paper we demonstrate how the intrinsic sensitivity of the CSEM method to hydrocarbon saturation can be utilised within a framework of well and seismic data in prospect appraisal and reservoir monitoring applications. This will be illustrated with examples of the H71 rock physics linking elastic and electrical properties along with recent case studies. CSEM methods use a high powered marine source to generate an electro-magnetic field within the earth.. The detected response of the earth to this electro-magnetic field is recorded by an array of receivers located on the sea-floor. By interpreting the recorded response using forward modelling and inversion approaches, the resistivity structure of the subsurface can be determined. In many situations electrical resistivity is driven by the properties and distribution of fluids in the earth. Resistivity measurements in well logs often show that commercial hydrocarbon deposits may be many times more resistive than surrounding lithologies. In principal, such variations should be readily detected using CSEM receivers. In contrast, seismic data are sensitive to boundaries between lithologic units but are less sensitive to fluid changes within these units. Given high quality seismic data, well logs, sophisticated seismic inversion and rock physics tools, we have the potential to relate changes in seismic rock properties to saturation effects. Nevertheless, the change in resistivity caused by variations in saturation should be much easier to detect. However, despite the increased sensitivity of resistivity data over seismic data for the determination of saturation, there are two inherent challenges to interpreting CSEM data. Firstly, the structural resolution of CSEM data is poor. Secondly, the cause of resistivity variations “anomalies” (particularly high resistivity features) cannot be uniquely linked to the presence of hydrocarbons in the subsurface when taken in isolation. In many situations these are equally likely to be caused by other highly resistivite material (for example, tight carbonates, salt bodies or volcanics). Both of these limitations must be addressed when considering the applicability of CSEM to answer a specific geophysical question, and as far as possible mitigated by the interpretation approach adopted. CSEM data can, of course, be interpreted in isolation, and if there were no seismic data or wells in the vicinity of the CSEM dataset (for example if a survey were performed in a frontier area), then this would be necessary. However, with no constraints on this interpretation, the result will suffer from the non-uniqueness and ambiguity which blight unconstrained interpretation approaches. Although resistivity is imaged, the poor structural resolution of the method means that such images are diffuse and difficult to interpret. The uncertainty in the depth of features is large, so that they cannot be unambiguously attributed to a particular stratum. If there are multiple resistive features, these cannot be easily separated, and small resistive bodies are likely to be lost or smoothed into surrounding strata during the inversion process. Even assuming that localized resistivity anomalies can be found, the cause of these anomalies cannot be unambiguously linked to the presence of hydrocarbon. In the presence of seismic and well information, the question that we are trying to answer with the CSEM data becomes significantly better posed. The question is no longer one addressed at finding a reservoir, but rather one of determining the content of a defined structure. Using seismic information the reservoir structure is known (but potentially not its content or extent), and we have independent constraints on the surrounding strata within which it is embedded. This is therefore a well constrained interpretation problem and one that the CSEM data are in a much better position to answer. It is clear that a careful combination of all three data types can supply information that is not available, or is unreliable, from any one data type alone. By integrating complementary sources of information and exploiting the strengths of each, estimates of rock and fluid properties such as gas saturation and porosity can be obtained with greater confidence than from any one data type alone. As we step from an exploration setting though to appraisal and monitoring of a reservoir the level of constraint on the geological model increases, and therefore so does our confidence in the CSEM interpretation. This increased confidence in the result transforms CSEM into a tool that can quantitatively map hydrocarbon distribution and time lapse changes in hydrocarbon saturation away from the well bore.
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Pore Pressure Prediction of a Field in Southwestern Part of the Malay Basin: A Basin Modeling Approach
Authors Ismatul Hani Shada Binti Idris, Peter Abolins and M. Jamaal HoesniPore pressure prediction has become crucial in various stages of frontier exploration, development, exploitation and drilling. Various methods are commonly used in predicting formation pore pressure, for example by using seismic velocity, wireline log-based pore pressure prediction, and geomechanics study. Basin modeling is an emerging approach in predicting pore pressure. Thus the development of a pore pressure prediction workflow using basin modeling provides an alternative approach. This project demonstrates a case study on the application of basin modeling for pore pressure prediction in the southwestern part of the Malay Basin. This study involves 1D, 2D and 3D basin modeling to evaluate the pressure distribution and behaviour. This study also considers the role of faults in controlling pressure distribution. Therefore, several faults have been incorporated into the 3D model. Lithology variations also occur, perhaps controlling the various pressure profiles. It is believed that both faults and facies control the pressure distribution. The pressure evaluation in this project was carried out mainly from 2D simulation. Porosity and permeability calibration was carried out to match the measured pressure data to the model. The final results of 2D simulation show a good
calibration between the measured data and the model.
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Seismic Facies Analysis of Group L and M Reservoirs, Southeast of Malay Basin
Authors Noor Iryani Jumari, Hamdan Mohamad and Nasaruddin AhmadSince PETRONAS Carigali Sdn Bhd (PCSB) has taken over Block XYZ in 2003, 3010 sq km of 3D seismic data were acquired and merged with existing 3D data acquired earlier over the producing fields. Currently, almost 80% of the block XYZ acreage is covered by 3D seismic data. The new data provides an outstanding opportunity to integrate the geology interpreted separately over the producing fields. From the available data on these groups, Group L and M has been identified as a potential new play and enhancing the stratigraphic trap in the south of Malay basin. PCSB has drilled eight wells deep down into the lower Group M, M110 and discovered oil and gas. The new oil and gas discovery in the southeast area of Block XYZ has proved that valid petroleum system is present in the deeper groups. Group L & M reservoirs have been identified as potential hydrocarbon play in Block XYZ. Seismic facies interpretation is very useful to investigate this concept. Group L and M are deposited in the earlier stage of the basin formation (synrift), which is in fluvial lacustrine environment (EPIC report, 1994). A seismic facies project have been conducted with the aim to describe the seismic facies in the study area and to interpret the depositional setting of these deeper groups in Block XYZ by integrating seismic facies characteristics on 3D seismic data, well log and core data from key wells. It also aims to provide an improved understanding of the local and basin scale distribution of potential reservoir sands in the southeastern part of the Malay basin.
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The Karap Mud Volcano Imaged on New 2D Seismic – Implications for Basin Analysis
Authors Franz L. Kessler, John Jong, Tran Quoc Tan and Hajime KusakaMud volcanoes can be seen in sedimentary basins, where clay and sand are accumulating within a “geological” short period of time. Several of them were mapped in the NW Borneo Basin, both Sarawak and Sabah (Liechti et al, 1960). In young clastic basins, following rapid burial, clay is liquefied. It moves upwards, intrudes sediment layers, and at times, reaches the surface. The plastic clay extrusions produce volcano-shaped cones than can reach a height of 20 m above area level in Sarawak (Kessler, 2008). The Karap mud volcano (Figure 1) is currently the largest active mud volcano in Northern Sarawak, and located in a hinge area of the “Baram Line”. This complex lineament system separates the “Baram Delta”, an area of poorly consolidated Mid-Miocene-to-
Recent clastic deposits (Kessler 2010), from the more consolidated “Central Luconia” (Figure 2). Mud volcanoes are complex features. Recent 2D seismic data acquired by JX NOEX, give for the first time insight into the structure of the volcano (Figures 3). The volcano's caldera is asymmetrical, and has formed as a collapse graben array on the tip of a major regional strike-slip fault zone (Figure 4). In the proposed model, the mud-volcanic activity stems from an interaction of surface waters with underlying overpressurized rock. In the funnel-shaped caldera, large quantities of meteoric water are collected, leading to a rise of hydrostatic pressure to a level in the order of 1200 psi. With increasing pressure, water penetrates deeper semi-permeable levels, and interacts with semimobile overpressurized pore-space gas. As the water mud rises, and de-gasses on the way up, gas bubbles are forming that later detonate on the volcano's surface. Arguably, the presence of mud volcanoes points towards compressive tectonism in the sub-surface, strike-slip combined with reverse faulting in the Karap case. Since mud volcanoes depend on overpressured rock, they point towards basin areas that are under-compacted. However, a direct link to charge and gas-bearing reservoir can currently not be made. Mud volcanoes also constitute an area of increased drilling risk.
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Low Relief Structure, A Favorable HC Accumulation Trap in Malay Basin
Authors Ji Ping and Norhafizah MohdMalay Basin had undergone three major vertical structure movements: extension, thermal subsidence and basin inversion. The important result of the inversion is the compressional anticline, include the low relief structure. Exploration activities in recent years demonstrate that low relief structure is a favorable HC accumulation trap. The discovered low relief structure HC accumulations have the following characters: 4 way dip structures (associated with deep seated faults) Low HC column (50 to 100 m) Large area (up to 60 km2), and HC filled near to spill point Very thick total net pay (over 200 meters) Multi layers with different contact systems. Low CO2 content comparing to high relief trap. Coastal plain and deltaic environment deposits match with the low relief structures make them excellent hydrocarbon accumulation traps in Malay Basin. The possible low relief traps lies between high relief structures or beneath the major gas fields which may be overlooked because they are not obvious in time domain or affected by gas sagging. Hence the comprehensive seismic analysis is needed, especially the 3D seismic velocity model.
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Conventional Approach Seems to Be the Best!
Authors Hijreen Ismail, M. Izham Kassim and Khairul Hamidi KhalidLateral and vertical velocity variations are among the key concerns for time to depth conversion especially in carbonate regime. A reliable velocity model should take account of these issues. The K prospect area is well known of its geophysical and geological complexity. The targeted and proven reservoirs are believed to be a type of platform carbonate. Furthermore, the existence of channel filled by shale throughout the whole K block, in the shallower horizon, i.e. at W level had caused pull down effects until the basement level. The poor seismic data quality and the unavailability of stacking velocities have developed more challenges to the study. There were three methods had been identified in order to produce a reliable velocity model meant for time to depth conversion purposes. The three methods are; average velocity model, 3D velocity model and conventional layer cake model. The first model is an application of well average velocity with main focus on the targeted reservoirs. The 3D velocity model had used a 3D grid as a platform to incorporate all TWT surfaces, well and DMO velocities. A statistical concept of modeling had been applied to populate the well (primary trend) and DMO velocities (secondary trend) in a single 3D model. Then, an anisotropy function
({well velocity / DMO velocities} X DMO velocities) had been generated as to integrate the anisotropy factor into this model.The third model is a conventional method which was generated based on observed velocity changes in sonic data vertically. Whilst, the TWT surfaces had been used as to control for lateral variations. Later, both well velocities and TWT surfaces had been incorporated with utilizing the Vo- K method as the basis of generating this model. Based on the statistical report of residual errors, the third model turns up to provide the least amount of erroneous.
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Regional Rock Physics Application for Improved Understanding of Thief Sands in Offshore Sarawak Basin
More LessSeismic data play a crucial role for hydrocarbon exploration. The seal integrity analysis is required for carbonate prospects ranking in Sarawak basin. The overlying capping shale has intercalated sands, which are termed as thief sands. The fluid content of these sands indicates seal breaching. Therefore, fluid characterization of thief sands may help to characterize reservoir seal and in-turn for prospect ranking. . These sands are quite shallow with depth range from 800-1500m. The recorded well logs are quite scarce and never analysed petrophysically in past. Reliable density and sonic( P&S) well logs along with relative amplitude preserved pre-stack data is very crucial to understand the seismic character of thief sands. The shale abundant columns at shallow depth drilled with overbalanced mud weight, induced large washouts and affected recorded well log curves. The density correction for washout zones is a must otherwise misinterpretation of seismic reflectivity may give an AVO pitfall. In general, conventional petrophysical analysis targeted for reservoir interval. However, to characterize shallower shale sections, a re-look on well logs conditioning is necessary before any further analysis. More than 25 wells widely distributed in Sarawak basin were selected for regional understanding of capping shale characteristics in terms of rock physics analysis. Input logs were quality checked for consistency and necessary corrections applied before putting them as input for rock physics modelling. Suitable rock physics model constructed to synthesized missing logs and poor quality logged interval. Gassmann fluid substitution modelling applied to understand the fluid effect on rock properties. Rock physical analysis for elastic and density logs indicates that brine and
hydrocarbon bearing sands are harder than shales in the Sarawak basin. The well log based forward modelling indicates that the sands always have high P-impedance than shales. The forward modelling results conform to the seismic amplitude variation in sands and shales. The seismic responses of sand tops are represented with positive reflectivity contrast and with dimming amplitudes of angle/offsets. The rock physics modelling and seismic well calibration helped us to delineate thief sands using pre-stack seismic analysis. The workflow and seismic analysis results will be presented in the paper.
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Delineation Stratigraphic Features Using Spectral Decomposition and AVO in B Field, Malay Basin
Authors Khairool Anwar Laksaman, Nguyen Huu Nghi and Goh Sing ThuIn the search for new hydrocarbon resources to optimize field development plan, delineation of stratigraphic features is becoming an important objective in the oil and gas industry. In the Malay Basin, most of the stratigraphic features are the channel systems which are filled up with either shales or sandstones (Mazlan B.M. et al., 1999). The sand-filled channels are potential targets of hydrocarbon accumulations, while the shale-filled channels can act as trap seal or barriers to fluid flow among reservoirs during field development. Their impacts on exploration and development have been observed from several fields in both northern and southern parts of the basin. Therefore the degree of accuracy in mapping the channel system is crucial to a proper evaluation of the reservoirs, which in turn will help improve the reserves base during the various stages of the field development. In this case study, a suitable methodology and workflow have been applied to address the above challenges for B field development.
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Integrated Approach to Identify Stratigraphic Prospect from Sparse 2D Seismic Attributes (AVO), Well Correlation and Geological Model – A Success Case from Genale B-2X in Blocks 3&4, Ogaden Basin, Ethiopia
Authors Eadie Noor Fadzly, Dodik Suprapto and Amri Shahril SaadudinGenale B-2X is a vertical wildcat exploration well drilled in Blocks 3 & 4 (Genale), Ogaden Basin onshore Ethiopia, 590m above sea level. The well is located approximately 800 km to the southwest of capital Addis Ababa, 15 km northwest of Genale-1 and 40 km southeast of El Kuran-1. It was drilled to evaluate the hydrocarbon potential in the Gumburo and Calub reservoirs. Geometrically, Ogaden Basin is divided into two sub-basins namely Western sub-basin which was relatively sagged during post Triassic period and Eastern sub-basin which was tectonically active throughout Permian to Tertiary period (as shown in the Figure 1). Prior to drilling, prospect Genale B was identified by bright seismic anomalies, extraction of seismic impedance and AVO seismic attributes from sparse 2D seismic data shot by PETRONAS Carigali Overseas Sdn Bhd (PCOSB) in 2006. The prospect is situated at the western flank of Ogaden Basin that experienced minimal structuration due to its close proximity to Negele Basement which shielded the blocks from intensely being further rifted. The well was successfully penetrated the Gumburo and Calub reservoirs respectively. Based on the petrophysical evaluation, three gas bearing reservoirs are identified in the Gumburo formation namely Upper Gumburo, Lower Gumburo and Middle Gumburo (Figure 2). High gas reading during drilling was observed in these reservoirs.
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Sequence Stratigraphic Study Paves the Way to the Discovery of Kinabalu A-1 Well
Kinabalu field is located in Sub-Block 6S-23 offshore Sabah, about 61 km to the northeast of Labuan (Figure-1). The field is subdivided into Kinabalu East (East Fault Block), Kinabalu Deep and Kinabalu Ultra Deep (West Fault Block). The Kinabalu field was discovered in 1990 and started production in 1993 (Kinabalu Field Development Plan, 2008). In late 2008 a regional sequence stratigraphic study of Kinabalu and surrounding areas was carried out to establish correlation of Kinabalu field within the Sabah regional Stratigraphic Framework with emphasis on understanding the stratigraphic location of the reservoir sections. In addition, the study was also aimed to identify upside potential for hydrocarbon exploration for the area. This is the first kind of this study since discovered in 1990 (Othman et al., 2008). Kinabalu A prospect is located on the upthrown side of Kinabalu East fault (Figure 2). The presence of Kinabalu A prospect was previously reported by the previous operator, but there was no further investigation made to evaluate the potentiality of this prospect (SHELL unpublished report, 2000). The present sequence stratigraphic study has managed to identify and verified the presence of Kinabalu A prospect in the Stage IV C at the 10A reservoir level and deeper section. In the area, where a petroleum system is proven by many discoveries, this potential subtle trap offered an attractive target. Further investigation with detailed structural mapping, resource assessment and seismic attributes studies indicated positive results on the presence of commercial hydrocarbon at Kinabalu A accumulations. As a follow up to the above studies and findings, Kinabalu A-1 well (KNA-1) was spud on 15 December 2009. The well was drilled to a total depth (TD) of 15, 423 ft MD/10, 023 ft TVD. The well has successfully penetrated hydrocarbon at 10A and 11A reservoir levels and declared as discovery. The KNA-1 well has been suspended for future development. This paper will discuss the workflow used for regional sequence stratigraphic study, which includes the integration of seismic stratigraphy, well log analysis, seismic attributes studies, core analysis and 2D geological modeling leading to the successful discovery of Kinabalu A-1 well.
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Azimuthal Anisotropic NMO Analysis for Amplitude Stripping Removal in Sumandak 3D Reprocessing
Authors Mazlan Ghazali, Edgardo Padron and Mehmet FerruhExploration and Production seismic interpretation relies on accurate seismic processing to make a good well proposal. The removal of amplitude stripping and large vertical discontinuities artifacts, observed in the previous processing (Figure 1), in the crossline direction at the Morris fault down thrown in Sumandak 3D Block, was one of the main objectives of the current PSTM/PSDM reprocessing project. In this paper, we present a reprocessing case study that applied the Azimuthal anisotropic concept to get a practical solution to this task. In seismic, Azimuthal anisotropic is referred to the apparent velocity dependence upon the azimuth of the shot and receiver geometry (Figure 3). The study area is in Samarang/Sumandak development block; in a zone with a oderate complex tectonic led by a remarkable normal fault which split two different geological environments. We will show, how using Azimuthal anisotropic NMO analysis helped to determine the appropriate parameters to correct the velocity field affected by azimuthal velocity anomaly.
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Multiple, Diffractions and Diffracted Multiples in the South China Sea: How Dense Does Our Acquisition Geometry Need to Be?
Authors Rosemary K. Quinn and Lynn B. ComeauxMultiples, diffractions and their multiples are a common feature of marine seismic data. In some areas of the South China Sea, the residual multiples are a significant problem as they are coincident with the reservoir section. In this instance, we need to devote significant resources to further attenuate the multiples, particularly the diffracted multiples. The challenge is to assess how much effort is sufficient and is that effort required during data acquisition, data processing, or both?
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An Integrated Geoscience and Engineering Efforts Leading to Increased Development Planning Confidence
Successful field development planning requires effective mitigation of geological uncertainties through integration of available G&G data and this has been the case for Jambu Liang faulted anticline (figure 1) which is currently operated by Petrofac Malaysia. Jambu Liang faulted anticline initiated by Cendor development in 2006 has been very prolific despite initially thought to be marginal. Following the success of Cendor, in 2008/2009 Petrofac resume the appraisal of fault blocks to the west and this appraisal campaign has lead to a potential new development of the West D fault block. For an effective development of the fault block, understanding reservoir characters and distribution especially in the prolific Group H reservoir which is geologically complex, is crucial.
Amongst the challenges inherent in the block is how to effectively delineate reservoir quality and sand continuity especially at poor seismic quality areas where most seismic response has been attenuated by presence of shallow gas (figure 2).
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