- Home
- Conferences
- Conference Proceedings
- Conferences
PGCE 2006
- Conference date: 27 Dec 2006 - 28 Dec 2006
- Location: Kuala Lumpur, Malaysia
- Published: 27 November 2006
41 - 60 of 60 results
-
-
Reservoir Properties and Depositional Environment of The Group M Cored Interval in Ledang Tengah, Block Pm309, Malay Basin
The early Oligocene Group M sandstone is relatively under explored in the Malay Basin but as exploration matures, the M group sandstones will be increasingly be targeted. The M group reservoirs in the Ledang-Anoa Field will be the oldest clastic reservoir in the Malay Basin to be developed. The Group M sequence forms part of the rift sequence and have been interpreted to be deposited within a continental setting in an alluvial-lacustrine environment. To determine the depositional environment, reservoir quality and identify the controlling factors in the reservoir quality variations, several cores were taken from the lower part of Group M, informally named as M40, M60 and M70 sandstones from the Ledang Tengah ST-1 well. From core descriptions and facies analysis work, supplemented by wireline log interpretations, the depositional system is interpreted to be a braid delta of McPherson et. al (1987). The braid delta system is characterised by progradation of a braided fluvial system into a lake. Depositional environments within this braid delta system composed of braided fluvial channels and in-channel bars, lacustrine mouthbars, palaeosols and open lacustrine muds. The almost complete absence of scour and fill structures (except for the base of the M70 core) that are common in many fluvial deposits is unusual and would suggest channel widening rather than channel incision as the main sedimentary response to fluctuating flow conditions. The sand bodies are thus likely to be aerially extensive and sheetform in geometry. Limited core and cutting samples have been analysed palynologically. In general, palynoligical recoveries were poor although samples were generally rich in organic debris. Terrigenous miospore assemblages were dominated by freshwater herbaceous swamps and cosmopolitan pollens. Mangrove taxa and savannah grassland pollens were rare. The high abundance of organis debris and highly degraded humic material indicated persistent soil erosion and deposition in a stagnant water, with brief periods of increased
freshwater run-offs marked by influx of freshwater algae and increase in miospores abundance and diversity. The absence of hinterland pollen species generally confirmed the reduced freshwater circulation and transport. Variations in reservoir quality in the cored section is controlled by primary factors, with sandstone grain size and clay content the dominant factors. However, the sandstones are generally texturally and compositionally immature. Although quartz and carbonate cements are present, the presence of authigenic kaolinite and to a lesser extent illite the results of secondary diagenesis, destroyed the primary permeability and rendered the quality of the sandstone reservoir poor. The best quality reservoir is associated with the coarsest grained and the more massive portions of the channel fill and delta mouthbar sandstones.
-
-
-
Sequence Stratigraphy of Blocks 102 & 106, Song Hong Basin, Vietnam
Authors Jaafar Unir and Othman Ali MahmudBlocks 102 & 106 are located in the Song Hong Basin, offshore Northern Vietnam in a water depth of 25 to 30 meters (Figure 1). Petronas Carigali Oversea Sdn. Bhd. (PCOSB) is the operator with a 50% interest. Other partners are PIDC (20%), SPC (20%) and ATIP (10%). Two dry wells have been drilled in Block 102 by the previous operator. In 2003 PCOSB drilled Yen-Tu 1X well in Block 106 with minor oil and gas discoveries and second well drilled in middle 2006 turned out to be dry well. A working petroleum system is believed to be present in the basin with couple of minor discoveries have been made in Blocks 102 & 106 and surroundings. As proven by the discovery of Yen Tu 1X and B10-STB-1X, source rock potential has the least risk. The lacustrine shale
deposited in the Oligocene syn-rift setting is believed to be the main potential for oil prone source rock. In addition, the early Miocene shallow marine shale and coal shows a good potential in generating oil and gas. In April 2006 XTG/XBS, PCSB carry out
Sequence Stratigraphic Study of Blocks 102 & 106 with the objective to understand the tectonic setting, basin formation, depositional model and the petroleum system of the area. In addition, this study aimed to answer the issue of correlation between Pretertiary Carbonate penetrated by Yen Tu 1X well and the exposed carbonate hills in Ha Long Bay (Figure 2). The correlation is crucial to establish analogue to the subsurface carbonate reservoir in Blocks 102 & 106. Plate tectonic reconstruction and geodynamic evolution shows that the Song Hong basin is a rift basin that formed in the late Eocene/Oligocene time. The basin formation and evolution is very closely related to the strike slip movements of the Red River Fault Zone. The basin has undergone a series of compressional and inversions events that provides the main structural framework for hydrocarbon trapping mechanism in the area. The study has identified eight sequence boundaries that separated the depositional package into eight sequences (Figure 3). The first package in the early Oligocene sequence is believed to be deposited in the lacustrine setting that provides the main potential source rock in the area. Seismic data and mapping shows that quite widespread of lacustrine setting during the early stage of the rifting that sufficient enough to have big lakes with low energy environment to be conducive for the deposition of good source rocks. The sediment inputs for lacustrine setting interpreted to be sourced from a multiple directions. However, during the early to late Miocene the deposition was controlled by marginal to shallow marine environments with the main sediment supply comes from the Red River in the northwest.
-
-
-
Submarine Mass-Transport Deposits in The Semantan Formation (Triassic), Central Peninsular Malaysia
By Mazlan MadonTriassic sedimentary rocks in the Central Belt of Peninsular Malaysia represent syn-orogenic sedimentation associated with the eastward-subduction and closure of the Palaeo-Tethys Ocean. This deepmarine “flysch” succession, of middle-upper Triassic age, is mapped as the Semantan Formation over much of central Pahang. The Semantan Formation consists of predominantly thin-bedded sandstone-mudstone facies, deposited in mud-dominated submarine fan systems. Individual turbidite beds are rarely thicker than 1 metre thick. Relatively fresh exposures of the Semantan Formation along the Karak-Kuantan Highway have given new insights into the sedimentary processes in the Triassic flysch basin. A change from distal to proximal facies eastwards between Karak and Maran indicate west-facing, active continental shelf-slope sedimentation. Hence, outcrops between Karak and Temerloh, east of the Bentong-Raub suture is characterized by “classical” flysch-like, thinly-bedded sandstone-mudstone facies, but west of Temerloh, and nearer to the paleo-shelf and slope, more sandy facies and thick-bedded turbidites occur. A fine example of proximal deep-marine facies association in the Semantan Formation is exposed at the Chenor Junction (Exit 821), kilometer 139 along the highway. South- and north-facing cuts on either side of the highway reveal interesting sedimentary features, which include large slide blocks (megaclasts), slumps, debris flow deposits, and associated syn-sedimentary thrust faults and glide surfaces. These features are strongly indicative of large-scale submarine mass-transport processes on the paleo-slope of the Triassic active margin. The Chenor mass-transport complex is made up of zones of incoherent slump deposits intercalated with well-bedded turbidite/debrite facies. In the lower part of the succession, there are at least two large blocks or megaclasts of sandstone-mudstone facies, measuring several metres in size, are encased in silty matrix. Along with other smaller sandstone blocks, these megaclasts are interpreted as slide blocks derived from slope failure up-dip of the basin plain. The internally stratified sandstone-mudstone blocks are strongly deformed internally by numerous meso-scale normal faults, which are evidently formed by ravitationally induced extensional deformation. Plastic deformation is also evident from the slump-related soft-sediment folds within the muddy matrix. Besides the chaotic “broken beds” and slump blocks, there are gravity-induced structural features such as rotational slumps, glide surfaces, thrust faults and associated soft-sediment folds. The slump folds and thrusts show vergence to the west, in the opposite sense to the tectonic vergence observed at other outcrops. A few of the well-stratified units show strongly inclined stratal surfaces, which may be attributed to lateral accretion of turbidite sand-lobes. Several sets of these inclined surfaces are bounded by erosional surfaces, which could have resulted from different episodes of turbidity flow. The association of incoherent mass-flow units with the better-stratified deposits reflects the close spatial and temporal relationship between submarine mass-transport processes and turbidity flows on the active Triassic paleo-slope and basin plain.
-
-
-
Seismic Rock Physics of The Miocene Carbonates: A Case Study from The Central Luconia Province, Sarawak
Due to increasing importance of oil and gas recovery and the growing realization that Luconia carbonate reservoirs are more heterogeneous than assumed in the past, rock physics analysis was employed to get better understanding on the relationship between the seismic properties of reservoir rocks (i.e velocity, density, rigidity) and their production properties (i.e facies, porosity, fluid type and saturation, pressure). Based on the analysis of 40 selected core samples from two fields in Central Luconia Province, the
followings conclusions can be drawn: 1. For general discrimination of tight and more porous facies, the best elastic property to be used is Lambda-Mu-Rho and Vp. Tighter facies associates with higher Lambda-Mu-Rho and Vp. Conversely more porous facies associates with lower Lambda-Mu-Rho and Vp. 2. For details facies-based discrimination of the porosity types (i.e chalky/mouldic limestone, sucrosic dolomite, argillaceous shale, tight limestone), the best elastic property to be used is Mu, Rho, SImpedance
and Vs. Log data cross-plot analysis shows that the use of Vp, AI and density are also possible but with more ambiguity. 3. For lithological discrimination, the Vp, AI and density can be used. However, the best result is obtained when S-Impedance, Mu or Mu-Rho are assigned. 4. For brine, oil and gas pore-fluid discrimination, the best elastic properties are Mu and Mu-Rho. Brine has the biggest Mu and Mu-Rho values, followed by oil and gas. 5. The type of matrix is generally calcite, whereas dolomite acts as grains. The abundance of pore types in descending orders is mouldic, vuggy, intercrystalline and fracture pores. 6. For pore and effective pressures identification and monitoring, the most sensitive elastic property is Vp. The presence of two gradients of pressure changes indicates the possibility of dual porosity. 7. For porosity determination, Vp and AI can be used. Bigger porosity associates with lower Vp and AI. Conversely, lower porosity associates with bigger Vp and AI. The Vp and AI can be obtained by applying Post Stack AI Inversion. 8. The time-lapse seismic analysis shows that time lapse seismic is feasible to be employed to monitor the changes of water saturation and pore pressure. The decrease of water saturation degree and the increase of pore pressure will slower the seismic wave velocity, extend the travel time and decrease the amplitude of first break. 9. Log cross-plot analysis reveals that Vp and AI can be used to discriminate lithology and pore fluids. The Vp and AI of carbonates are higher than the shales. The Vp and AI of water are higher than the gas 10. AVO analysis shows that Vp-Vs relationship is linear and the best-fit equation lines will be different at different pressure conditions. Increase of pore pressure will decrease the Vp and Vs linearly. Conversely the increase of overburden pressure will linearly increase the Vp and Vs. The Vp-Vs gradient change resulting from the change of pore pressure is bigger than the change due to overburden pressure. 11. AVO class cross-plot analysis shows that the type of carbonate AVO is class III. However, brine and gas condition cannot be discriminated using AVO intercept and gradient since their values are overlapped.
-
-
-
Regional Controls on Carbonate Developments in Central Luconia, Offshore Sarawak
Authors M. Razali Che Kob and M. Yamin AliThe Central Luconia province in the offshore NW Sarawak is a stable platform, flanked by two areas of active deltaic sedimentations. It is characterized by extensive development of carbonate which started in the Early Miocene through Late Miocene. Up to present, more than 200 Miocene carbonate build-ups have been mapped and some 70 have been tested (Hutchison, 2005; Vahrenkamp et al, 2004, Epting, 1980). The Central Luconia is part of the present-day Sunda platform, and forms its NE shelf edge. It is
located in an intermediate position between areas of subsidence and faulting in the north and zones of pronounced compressional tectonic in the south. It is separated from the Baram delta province by a shear zone associated with the West Baram Line in the NE, and to the SW is the Penian High. Together with other structural provinces of Sarawak, the Central Luconia is believed to be an integral part of the Sundaland and is interpreted to be underlain by the continental basement (Hutchison, 2005). The Sarawak basin as a whole was formed as a result of NW-SE trending right-lateral fault movement during the late Oligocene-Miocene times (Ismail, 1997). This dextral movement is thought to be responsible for creating the NW-SE trending paleo-highs and lows and had also positioned the paleo-coastline in the same trend. However, due to fluctuating nature of the sea levels and tectonic tilting, these coastlines appeared curvy during most of the lowstand sea level phases. Structurally, the Central Luconia appears to have been rotated in counter-clockwise direction. The block is bounded by shear zones, associated with a dextral-wrench movement along the West Balingian line. Beside this, a few dextral-wrench faults propagated in the same trend were described by Ismail (1997),
namely, the Mukah Line, Igan-Oya line and others. It is likely that the Central Luconia formed the central part of the rotated blocks. Recent study on regional seismic lines indicates that the Central Luconia has undergone extension during Middle Miocene and was followed by continuous compressional phase for most of the Middle to Late Miocene. During the extensional and the subsequent isostatic readjustments, the Central Luconia was a depression bounded by the uplifted regions which formed the basin edges in the SW, south and SE. Areas in proximity to the main uplifted region in the east were dominated by clastics, whereas, the carbonate occurred on the rifted margin in the west associated with the rising of sea levels. The subsequent compressional tectonic had resulted in inversion and folding of the basin-fill strata. This phase was responsible for elevating the Central Luconia region and characterizing it with widespread presences of tight anticlinal folds. These folds formed the ideal sites for widespread carbonate growth during high sea level phases of the latest Middle Miocene to Late Miocene. The fluctuating low sea level phase of the Late Miocene had punctuated the buildups by karstified surfaces that indicate subaerial exposures and had demised some of it. With exception of a few buildups, most were drowned during the major sea level rise at the base of Pliocene.
-
-
-
Lithology Discrimination through Velocity Analysis – A Solution trough Method
In this paper, we have implemented the technique to a study area that was located in deep water and seven geological stratigraphic units were used for velocity analysis. Issue arises when we tried to tie the stratigraphic units to well markers. A thin stratigraphic unit is prominent in the seismic section but not being interpreted in the well as a unit (Figure 2). We expect that this thin layer will create variations in the provelocity analysis within the target location. Due to the variations, checkshot seemed to be inaccurate in
further calibrating for time-to-depth conversion below the thin sedimentary layer. A study of solution trough has been applied with the composite displays of the solution troughs indicate that within the top and the second uppermost units, there is clearly inconsistency in stratigraphic unit parameters.
-
-
-
Drilling of Deep-Seated Reservoir in High Pressure Regime in the North of Malay Basin
More LessPMU Petronas has taken initiative drilling wells in high exploration risk areas such as deep-seated high pressure and high temperature (HPHT) reservoirs, since 1996. PMU drilling campaign in the deep-seated and high pressures wells has resulted a few field discoveries, such as Bergading Deep, Sepat Deep and Guling Deep-1 wells. The challenges of drilling deep-seated and high pressure wells gives us a significant experiences in predicting the abnormal pressures and handling the well operations especially while drilling through the critical zones within the leak-off pressure limits. (figure 1). In drilling high-pressure wells in Malay basin, we had an experiences of having severe losses of the mud, well kicks and operational difficulties such as stuck pipes, hole stability and hole caving while drilling of the well. Of course, surrounding well information such as formation pressures, velocity, well logs will help geologist and drilling engineer in designing the well, determined mud recipes, bit types and prediction of pore pressure. All these preparations are very important, prior to drill and while drilling the well to ensure the success of drilling and safety of the personnel onboard. In the drilling of deep reservoir well, pressure prediction is very important to be carried out. The data from nearby wells has to analyze in predicting abnormal pressure such as seismic velocity, formation pressures from RFT/ MDT, mud weight were used from nearby wells, porosity, density and well log curves. The good data would predict the presence of abnormal pressure based on the deviation on porosity trend, density and reversal of velocity data with the increase of depth. The understanding of the mechanisms of overpressure is very crucial in predicting the overpressure pressures. The mechanisms of abnormal pressure in Malay basin were observed mainly due to the following reasons;
i) Under compaction or overburden – at the center of the basin
ii) Uplift – tectonic compression and structural inversion
iii) Inflation or late over pressuring – at the basin flank
-
-
-
The West Crocker Formation Outcrop at Kingfisher-Sulaman, Kota Kinabalu: Sedimentary Features and Facies Succession
More LessA section of the West Crocker Formation (Oligocene-Lower Miocene) is spectacularly exposed at the Kingfisher-Sulaman residential district, along Jalan Sulaman, north of Kota Kinabalu in West Sabah. The ground clearing for the development project has exposed more than 200 m of deep-marine succession. This outcrop is one of many exposures that are the subject of an ongoing collaborative research by Petronas Research and Universiti Sains Malaysia. Some preliminary findings are presented in a separate presentation at this conference (Mohd Nizam et al., 2006). This poster is pictorial tour of the outcrop, arguably one of the best exposures of the West Crocker Formation. Over 230 m of steeply dipping, medium to thick-bedded sandstone and mudstone are exposed on the cut slopes of this outcrop. The sandstone facies is predominantly fine grained, though some are medium to coarse, and even pebbly (granular) in places. The beds range from a few 10s of metres to more than 30 m thick. Many have sharp tops and bases, the latter often erosive. Internally they appear to be structureless, though faint consolidation lamination or dish structures are quite common. Some beds have well-developed load and flame structures. Flute marks and rip-up clasts are also common, indicative of the erosive nature of the depositing flows. There are some thin turbidite units (< 1 m) with graded bedding and Bouma subdivisions, but these do not appear to be very common. A most spectacular feature of this outcrop is the occurrence of a slump interval at the top of the succession, consisting of several large (metre-scale) sandstone blocks “floating” in a muddy matrix. The succession may be subdivided into four main intervals, comprising coarsening-upward and fining-upward parasequences. The lowermost interval, comprising five fining-upward cycles, represents eposits of a channel complex. This is overlain by a sand-dominated interval interpreted to be middle to lower fan lobe complex. The third interval is a simple, fining-upward parasequence, which is thought to have been deposited within the upper fan/slope channel. The uppermost interval is mud-dominated and characterized by the presence of large sandstone blocks in shale, which is interpreted to represent muddy inter-channel/slope deposit. Most of the sandstone units in the Kingfisher-Sulaman outcrop were probably deposited as highdensity flows (debrites) rather than turbidites. The sandy nature of the succession and the preponderance of debrites and slump features suggest that the succession represents part of mass-transport complex in a slope or base-of-slope setting.
-
-
-
Low Co2 Potential Hydrocarbon Block Sk 301, Rajang Delta, Offshore Sarawak
More LessBlock SK 301 is open block, located in the Rajang Delta shelf, offshore Sarawak, East Malaysia PMU offers an opportunity to acquire interest of this highly prospective block. This presents a chance to acquire a position in one of the most dynamic, rapidly-expanding theatres of SE Asian E&P, in the virtually unexplored, large Rajang Delta which contains only four exploration wells and one delineation well within a 8164 sq.km area. One of the wells (L4-1x, Shell, 1970) is a proven gas discovery, with reserves estimated to be in the order of several hundred BCFG and which also has the potential for oil, as both L4-1x and delineation well Hibiskus-1 (Idemitsu, 1988) had oil shows. Last contract terms handed by YPF Repsol Malaysia were improved during the late 90’s by Petronas, and together with potential access to nearby producing infrastructure and with benign operating conditions and shallow water depths (+/-100 -150 m), the area has favorable economics. I2 wells drilled by YPF Repsol (Sook-1/st and Laya–1, 2003) penetrated good gas shows in undeveloped sands.
-
-
-
Sedimentary Facies and Depositional Framework of the Tertiary West Crocker Formation around Kota Kinabalu, Sabah
Authors Nizam A. Bakar and Abdul Hadi Abd Rahman and Mazlan MadonThe Oligo-Miocene West Crocker Formation in Sabah has been interpreted as part of an extensive, unconfined submarine fan system, but a detailed description of the sedimentary facies are lacking. This paper describes the sedimentary facies and their relationships, based on a study of eight major outcrops of the West Crocker around Kota Kinabalu, Sabah. Seven sedimentary facies have been identified. Facies A - pebbly, medium-to coarse-grained, amalgamated sandstone. This facies consists of poorly sorted, massive (structureless) sandstone beds with thicknesses ranging from 1 to 38 m. This facies generally have a very high sandstone-to-shale ratio. The bases of sand commonly have flame and load structures. Mud clasts and rip-up clasts are common, with rare carbonaceous and sandstone clasts. Facies B - fine- to coarse-grained sandstone, generally massive, moderately to poorly sorted, and has post-depositional dewatering structures, e.g. dish structures and pipe marks. It has a lower sandstone-to-shale ratio compared to Facies A. Rip-up mudclasts and sole marks, such as flute and tool marks, are common at the base of this facies. (iii) Facies C - composed of sharp-based, graded beds, which may form complete Bouma sequences. The sandstones are commonly laminated or crosslaminated. (iv) Facies D - parallel laminated, very fine- to medium-grained sandstone, and shale. It may be organized into Bouma sequences, but with the Ta division absent. (v) Facies E - fine- to coarse-grained thinbedded sandstones, occasionally with climbing ripples, lenticular bedding, and intraformational rip-up clasts. Trace fossils are common, and include Nereites, Spirorhaphe, Megagrapton, Paleodictyon, Cosmorhaphe and Helminthoida. (vi) Facies F - “chaotic” shale-rich units with slumped beds and syn-sedimentary folds; and (vii) Facies G - consist of fine-grained, pelagic and hemipelagic deposits. These facies are organized in facies associations that represent different deposits of the submarine fan system. These are: (i) slope deposits – dominated by facies F and G, with subordinate facies A and B; (ii) channel-fill deposits - generally showing upward-thinning and upward-fining packages, in which facies A, B, C and D are dominant, with minor occurrences of facies E and F; (iii) levee or overbank deposits - dominated by shale with very thinly bedded sandstone, showing thinning-upward packages and dominated by facies E and G, with minor facies F; and (iv) lobes or sheet sands – comprising coarsening-upward packages, 15-30 m
thick, and are characterized by facies A, B, E, and G, with minor Facies F.
-
-
-
Modeling Seismic Amplitude Attenuation – Q-Absorption Perspective
Authors Ahmad Riza Ghazali and M. Faizal A. RahimSeismic imaging in heterogeneous media is complex. This is due to the integration of the wave equation is no longer gives simple Green’s Function analytical solutions. Calculation of the Green’s Functions must be done kinematically to estimate travel times from sources to receivers (τ). Dynamically, the amplitudes are affected by anelastic attenuation, spherical divergence and the directivity pattern of the wavefronts in the velocity model. Reflection and transmission coefficients that produced amplitudes received at the receivers are also affected by the directional of the acquisition arrays and must be analyzed at every major acoustic impedance interfaces (Robein, 2003). Attenuation and dispersion effects have been modeled using a complex velocity (Aki and Richards,
1980). Wang (2004) proposed method using Gabor transform to estimate P-wave amplitude attenuation in the seismic due to Q-absorption, that is also called Qp factor, and applied the Q-attenuation inverse filter for correction. Chapman et. al. (2005) has shown that via laboratory experiment, the near surface scattering due to heterogeneities can give the same effect as Q-attenuation. He showed that body waves as it hits the scatterers produced secondary wavefronts that creates secondary Rayleigh waves and can be suppressed using near receivers multi-channel inverse filter.
-
-
-
Modeling Velocity Heterogeneities for Seismic Imaging and Depth Conversion
Authors M. Faizal A. Rahim and Ahmad Riza GhazaliThe velocity models is crucial in seismic imaging as it controls the quality of the migrated image and it is also crucial for time to depth conversion. Surface seismic in principal measures mainly the horizontal velocity component and sonic logs measures the vertical velocity component of the earth. The ratio of these velocities creates anisotropy. The term ‘provelocity’ will be used in the present work specifically to denote the parameter derived seismic processing as ‘velocity’ because this is a modelling parameter that can be quite different from the true propagation velocity in the ground (Al-Chalabi, 1994), (Ghazali, 2006). Much of the information about the velocity distribution in the ground is derived from NMO stacking (maximum coherency stack) provelocity, Vmcs. These stacking provelocities are used as basis for estimating the root mean square ‘RMS’ provelocities and are often treated as being synonymous to each other. The difference between the root mean square and average velocity depends on the parameter known as the heterogeneity factor. The heterogeneity factor is a positive quantity being near to zero only when all of the layers have the same velocity as it is close to homogeneous. Its value is independent of the order of layering. Therefore the rms velocity equals the average velocity when the ground is homogeneous (Robein, 2003).
-
-
-
Malay Basin Co2 Predictability Using Seal Integrity and Equivalent Grain Size
Carbon dioxide distributions vary in Malay Basin. Structural relief and trap seal effectiveness are the main controls over the distribution of carbon dioxide percentage (Mansor Ahmad, Petronas, personal communication). These conceptual observations could be explained by three principals, viz. CO2 segregation in reservoir, cap rock sealing capacity and hydrocarbon fill-spill. Structural closures with vertical relief of more than 150 meters will accumulate relatively high concentration of carbon dioxide. Closures with vertical relief or hydrocarbon column less than 150 meters will accumulate relatively low concentrations of carbon dioxide if top and lateral are effective. Stratigraphic plays conventionally trap low CO2 accumulation due to their subtle relief and effective seal.
To understand the CO2 distribution, ten fields in Malay Basin were selected randomly. These fields are Noring, Jerneh, Bunga Raya, Jambu, Angsi, Bujang, Resak, Beranang, Inas and Ledang. To calibrate CO2 distribution, five fields were selected; namely Jerneh, Bunga Raya, Angsi, Resak and Beranang. These fields have a wide range in CO2 concentration and vertical structural closures ranging from 50-220 meters. The Jerneh structure is a 4-way closure with average relief of 150 meters. Group D and E gas
reservoirs in this field encountered low CO2 content, ranging from 0.98 - 7.0%. The CO2 percentages in this field support the theory of CO2 segregation and spill model. These results support the theory of effective seal, which is confirmed by the Equivalent Grain Size (EGS) values ranging from 10.14 - 10.99 phi. Bunga Raya structure is 4-way closure on the northern part and a 3-way closure fault dependant on the southern part. The vertical relief ranges between 30-80 meters. The CO2 content is high (45% to 55%) with an EGS value of 8.15 phi due to silty top seal. From the EGS values, the structures expected are mixed type traps in the northern part with possible oil potential down dip or a possible capillary limited trap. Angsi is low relief and faulted anticline trending NW-SE. The vertical relief is approximately 70 meters in Group I, which increases to about 120 meters deeper at Group K. Structural and stratigraphic traps types are encountered in this field. The field encountered low concentrations of CO2 due to low structural relief, which is supported in tandem with high EGS values ranging between 8.50 - 9.20 phi. CO2 content is low in Group I channel sand due to stratigraphic trap with low hydrocarbon column. Resak is a 3-way fault dependent closure. The CO2 content varies vertically and aerially in every reservoir due to differences in top seal capacity. Thicker and cleaner overlying shale provide effective seal in Group I20.1 reservoir. I30.1 and I50.1 reservoirs contain low CO2 with the EGS value of 8.70 - 9.0 phi. Different situations exist in the I80 and J Group reservoirs, where the CO2 content is high with less values of EGS, ranging from 7.70 - 8.50phi. Beranang structure, located to the south of Resak structure, is a downthrown normal fault dependant closure with relief about 55 meters. Each structure has no relationship due to the different pressure system. This structure encountered high CO2 with EGS value ranging from 4.0 - 5.9 phi. Understanding the parameters that could possibly control CO2 distribution in a basin and top seal capacity will give an explorationist an interpretational tool to explore for low CO2 hydrocarbon prospects. The vertical relief or hydrocarbon column limit varies from basin to basin due to difference in cap rock effectiveness. Different lithologies will have different capillary entry pressures that need different buoyancy pressures before it breaches under similar condition. The EGS method helps in predicting the seal capacity, which is an important element in identifying the low CO2 plays.
-
-
-
Discovery Well Pc4-1: An Integrated Image Log, Acoustic Waveform, Nmr, Reservoir Pressure, Sampling and Testing, and Petrophysics Study
Authors K. Zainon, A.A. Bal, M. Altunbay, J. Burge, R. Din, W. Ong and D. Pantic and J. WadsworthIncreased volatility of the gas/oil prices coupled with the high cost of finding new reserves have resulted in an urgent need for better managing newly-found reserves. With this incentive and opportunity, we have undertaken an integrated approach of creating the definitive tool-box for better description and characterization of the reservoir cut by PC4-1 located in Block SK310, East Central Luconia, offshore Sarawak, East Malaysia. PC4-1 is a gas discovery with 454 m gas column with varying amounts of movable
water in the studied log coverage of 2648-3274 m (626 m). With the help of integration of geological information, conventional openhole logs, NMR, image logs, and fluid sampling and pressure tests, we have derived and modeled static and approximate dynamic
properties of the formation. The work scope in its entirety encompasses a thorough analysis of the geological and wireline datasets acquired in PC4-1 in order to quantify the key reservoir features required for distributing petrophysical properties in three-dimensional space using geologic models. The resistivity (STAR) and acoustic (CBIL ) images of the borehole wall, MREX partial porosity distribution, and Stoneley reflectivity were used for a geological analysis for defining image facies. The reef complex comprises four distinct facies and localized vuggy and karstic zones. The CBIL image and Stoneley reflectivity was particularly useful for locating potential karst/vuggy porosity zones. Stoneley reflections are very sparse and the losses of acoustic energy are rare. A stochastic and deterministic method is used for conventional petrophyscial analysis. The results are comparable, which lends confidence in the parameters used and results obtained. Water and hydrocarbon saturation are computed using conventional Archie model bulk shale analysis techniques. A water level is interpreted at 3238m ahbdf. The Acoustic Log Hydrocarbon Indicator (ALHI) technique is used to generate flag curves for each identified fluid type on a zonal basis. Since NMR data was acquired in the 8.5” hole, we can calibrate the ALHI against the actual NMR results and provide fluid typing for the 6” hole which was not covered by the NMR. There are no core data available for calibration of wireline logs; however, the latest technological advances in MREX and RCI tools in conjunction with the conventional petrophysics, and most recent computational techniques, provide the proper foundation for models and correlations generated from the petrophysical trends. Petrophysical properties such as ermeability, porosity, wetting and non-wetting phase saturations are computed, modeled, and the key controls of the productivity have been extrapolated into the 6” hole sections where we have no MREX data. Furthermore, the analogous behaviors of capillary pressure and 1/T2 decay versus saturation data provide a methodology for deriving synthetic capillary pressure information directly from NMR logs. The methodology and theoretical assumptions are explained in various publications. The technique is extended for PC4-1 by using model equations that would transform the “partial porosity versus time” distribution into capillary pressure versus wetting-phase saturation, after correction of partial porosity bins for gas and polarization effects and because there is no “diffusive coupling”. The main reason behind attempting to derive capillary pressures is to obtain a more representative BVI profile than from a fixed-T2cutoff type of profile. The transformation is done for each MREX level-spacing; the resultant curves generated are representative of
minor changes in the lithology or formation. This data feeds into a Productivity Analysis.
-
-
-
Pitfalls in the Application of Sequence Stratigraphy to Well-Log Correlation. Comparative Outcrop Studies of Reservoir Analogues in Sarawak
Authors Muhamad Pedro Barbeito and Marc BuddingThe application of sequence stratigraphy to the clastic oil and gas reservoirs in the Sarawak offshore has not lived up to the initial high expectations. To find a cause and remedy for the often-disappointing results, outcrops of the Nyalau, Lambir, Miri and Liang Formations were studied in the exposed Neogene of the Tatau, Bintulu and Miri regions of Sarawak. The outcrops appear to be providing good analogues for the shallow marine and coastal reservoirs in the offshore subsurface, as far as they were deposited within the coastal reach (between high- and low-stand shorelines). All formations consist of a series of regressive-transgressive tongues of coastal and coastal-plain sediments in marine shales. Five key facies-associations can be distinguished with similar characteristics in all four formations and in cores and logs from offshore wells: (1) shallowing shelf; (2) regressive shoreline; (3) coastal plain; (4) incised valley; (5) transgressive shoreline, and (6) deepening shelf. These associations are separated by (a) the
shoreface transition zone; (b) the emerging shoreface surface; (c) the sequence boundary (d) the marine flooding surface; (d) the mud line and (e) the maximum flooding surface. The transgressive shoreline association can usually be subdivided into an inshore tidal (backbarrier/ lagoon) and an offshore tidal unit, separated by an erosive marine-flooding (ravinement) surface left by the landward migration of the shoreface. Even in outcrops, with a wealth of geological information at hand, two practical problems become
immediately clear: – It is very difficult to correlate the major (4th to 5th order) regressive-transgressive units between outcrops. The resolution of the currently available bio-stratigraphy (based either on planktonic foraminifera or palynomorphs) is insufficient to tell individual tongues apart, let alone to relate them to global sea-level fluctuations. Even differentiating between the Lambir and Miri formations on bio-stratigraphic grounds is difficult. – Only four of the six bounding surfaces can usually be identified in outcrop. This does unfortunately not include the two key bounding surfaces of classical sequence stratigraphy: the sequence boundary and the maximum flooding surface. In most outcrops the sequence boundary is not present as an erosive surface, but as a more subtle “surface of maximum regression”. The position can often only be inferred where an a-sequential pattern in the succession of lithofacies indicates a discontinuous seaward shift of the depositional system. In many cases, especially in the deposits of low-stand coastlines, this surface may be represented by a sand-on-sand contact, precluding recognition from logs. The problem is compounded by the presence of several –more frequent- alternative candidates for the sequence boundary: (1) the sharp erosive base of the shoreface, as found in several forced regressions in the Lambir Formation; (2) the ravinement surface of the transgressive shoreline found in many new outcrops of the Nyalau and Liang Formations; (3) the erosive base of distributary channels, common in many coastal plain associations (4) low-angle, sub-horizontal thrust faults, commonly observed in the Lambir Formation, and presumable also present in compressive structures in the subsurface. Possible remedies for these problems include: A more rigid lithofacies analysis to preclude erroneous picks of the sequence boundary. For wells without core data, this implies the design of a more refined logfacies scheme using overlays of wireline logs rather than Gammy Ray logs only (see Budding, 2006,
elsewhere in this volume). In addition, improving the resolution of bio-stratigraphy might enable the distinction of individual 4th order sequences and possibly lead to a calibrated sea-level curve for the region. Nanoplakton may provide a viable solution.
-
-
-
Hydrocarbon Generation and Inorganic Modeling of Carbon Dioxide Generation and Expulsion in The Malay Basin, Peninsular Malaysia
More LessThe presence of carbon dioxide in the Malay Basin has often raised queries regarding its origin and distribution. Accumulations in the Malay Basin have been shown to originate from both organic and inorganic sources (Figure 1). Organic sources comprise the decomposition of organic matter with increasing as well as the cracking of hydrocarbon products at high temperatures. Inorganic sources include the thermal breakdown of calcareous shales and limestones, as well as the diagenetic reactions in siliciclastic rocks whereby carbonate minerals such as siderite, dolomite and calcite in clastic sediments react with silicates at temperatures greater than 320°C to generate carbon dioxide. In addition, carbon dioxide contents in both associated and non-associated gases in the Malay Basin can vary up to a maximum of 90%. Our studies indicate that it is erroneous to generalise that carbon dioxide occurrences increase with increasing depth. Another important observation is that low carbon dioxide percentages (less than 20%) do not necessarily indicate an organic origin. However, in most cases where the carbon dioxide contents are greater than 40%, more often than not, they are of inorganic origin. Modeling of the Malay Basin’s hydrocarbon and inorganic carbon dioxide generation was performed using personalised kerogen kinetic parameters and carbonate decompositional kinetic parameters of actual Malay Basin’s samples. The former were determined for the Bergading Deep-1 Group E coals, Beranang 6F- 18.1 Group I fluviodeltaic coaly shales and Bunga Raya-1 Group K lacustrine shales (Figure 2). For the assessment of carbon dioxide generation from carbonates, the decompositional kinetic parameters were determined for the Bunga Raya-1 Group M calcareous shales and limestones. These new kinetics data provide a better control on the results of the carbon dioxide generation modeling as they are specific to the Malay Basin samples. Additionally, predictions of carbon dioxide generation were also determined from modeling
the diagenetic reactions within the penetrated sediments using the method of Cathles & Schoell (PGCE 2006). Three locations were selected for the carbon dioxide kinetics modeling, namely Bujang Deep, Angsi and Bunga Raya. Using the newly-acquired kinetic parameters, we were able, for the first time, to determine the timing of inorganic carbon dioxide generation and expulsion as well as its most likely origin in these areas. To ascertain the trapping feasibility of the generated carbon dioxide, the resulting timings were compared with the thermal subsidence and basin inversion of the Malay Basin which occurred between 21 Ma to 6 Ma, with peak trap formation at around 16 Ma. Based on the carbonate decompositional kinetics modeling, the carbon dioxide observed in Bujang Deep should have a mixed origin due to expulsion from the following: both the Group M calcareous shales and limestones at 21 Ma and 20 Ma, respectively (Figure 3), and from the Group K siliciclastic reactions at 14 Ma. The origins were validated by actual measured data whereby the Bujang δ13CCO2 fall within -3 to -6o/oo isotope values, indicating an inorganic origin. There are also carbon dioxide samples with isotope values of - 11.4 and -12.2o/oo, suggesting a mixed origin. The Dulang, Semangkok and Tangga fields located within the middle part of the Malay Basin also exhibit high carbon dioxide occurrences (Figure 1). In the Angsi area, the kinetics modeling indicated that the carbon dioxide encountered by the well should have a strong inorganic influence due to the thermal breakdown of the Group M limestones (Figure 4). Modeling indicated the timing of expulsion to be around 14 Ma. Carbon dioxide contributions may also be expected from the Group M calcareous shale but, since it was generated much earlier than the trap formation at 24 Ma, it is presumably lost. With the bottom temperature of the section being only at 200°C, the diagenetic reactions have not yet started. Traditionally, the carbon dioxide contents of Angsi-1 of less than 20% would be thought of as suggestive of an organic origin. However, the δ13CCO2 values range of between of -5 and -7o/oo tell a different story; these carbon dioxide gases are actually of inorganic origin. Kinetic modeling results corroborate with this indication, thus validating the model. The Bunga Raya kinetics modeling results suggest an inorganic origin for the carbon dioxide observed in the Bunga Raya-1 well, by virtue of being sourced from the Group M limestone at 2 Ma (Figure 5). Again, diagenetic reactions did not contribute to the carbon dioxide accumulation in Bunga Raya.
-
-
-
Calculating Volume Fraction of Clay, Silt and Sand from Nmr Logs
More LessNuclear Magnetic Resonance (NMR) tools measure a lithology independent porosity through the processes of longitudinal relaxation (T1) or transverse relaxation (T2) of hydrogen nuclei. It is generally accepted that in water-filled pores, the T1 and T2 distribution profiles are equivalent to a pore size distribution. In clastic rocks, small pores are associated to clay bound water and capillary bound water, and there is a strong correlation between pore size and grain size. Since clay, silt and sand can be classified in terms of their particle size, the distribution of T2 relaxation times can also be used to estimate their respective proportion within the rock matrix. Mattheson has shown that the NMR relaxation time of clays depends on their compaction, and that there is no universal T2 cut-off to differentiate clay types. However, we have observed that the partitioning of T2 distribution into clay, silt and sand is a robust method that can be applied to the following clastic rocks evaluation: • Clay volume based on pore/grain size; direct measurement, independent of radioactive or heavy minerals and of formation fluids. • Silt and sand volumes based on pore/grain size; direct measurement, comparable to Density vs. Neutron or Matrix Density vs. Capture Cross-section methods. • Lithology independent Total and Effective Porosities; direct measurement comparable to Density, Neutron or Sonic porosities. • Volume of Irreducible Water based on pore size; direct measurement, essential to reduce uncertainty of hydrocarbon volume in shaly sands and thin beds. We present applications of this method and a comparison to conventional analysis on log data from North East Borneo deepwater environment.
-
-
-
Malay Basin Petroleum Systems and Sequence-Stratigraphy a Unified Geological Theory of Everything?
More LessAfter Albert Einstein’s discovery of The Theory of Relativity in 1915, the following 40 years of his life were devoted to formulating a Theory Of Everything (TOE theory). His contemporaries researched Quantum Theory, dealing with, among other things, mathematical expressions of probabilities and the existence of parallel universes. Einstein’s famous response was “God does not play with dice!” He died still searching for the answer! As we move through this early 21st century, a peak oil crunch looms. And are we still playing dice in the way we look for oil and gas? Do we continue to take unnecessary risks with our exploration dollars? Can we hedge our bets using some kind of unified Geological Theory of Everything to find additional resources in ‘supposedly’ mature hydrocarbon provinces such as the Malay Basin? One possible way, albeit subjective, is to combine mother nature and math – like using logarithmic dice. The method is to combine a deterministic fractal log distribution of ranked hydrocarbon field sizes with an integrated petroleum system analysis using seismic-sequence stratigraphic tools. This powerful method enables the geoscientist to figure out if large hydrocarbon discoveries remain to be discovered. It locates basins or hydrocarbon fairway trends with remaining or yet-to-find (YTF) resources and quantifies those resources within any trend. With this objective in mind, Petronas Petroleum Management Unit (PMU) and several PSC study group partners recently commissioned PRSS to undertake a multidisciplinary regional study to identify new play types in the Malay Basin. This involved a sequence-stratigraphic analysis in conjunction with 3D burial history modeling, augmented by new biostratigraphic well calibrations, CO2 distribution studies, cap-rock
integrity and section restoration work. The results of this study are exciting and in part are summarized in this keynote address – and prove the Malay Basin is by no means a mature hydrocarbon province. Since the study is regional in nature and scope, we will be indicating in general terms where we might look for more oil and gas in the Malay Basin – the sweet spots, and suggest play types with potential YTF resources. The field sizes distributions from actual and implied fractal distributions are surprising. Basically this method gives the PSC operators a reserve target to hunt or identify. Integrated burial history modeling in conjunction with regional seismic-sequence stratigraphic mapping of reservoir facies has identified that sweet spots for YTF liquid hydrocarbons will tend to be focused along the peripheral margins of the basin. Traps occur in a variety of plays ranging from lacustrine turbidites, incised valley fills, canyon deposits, synrift subcrops, fractured Pre-Tertiary basement and carbonate plays. Basin centered hydrocarbons or basin centered gas (BCG) plays will tend to be the main YTF hydrocarbon type in the basin depocentre and, as proven in many basins world wide, can be expected to extend onto the basin flanks – or the external ‘steer head’ portion of the basin margin. The size and number of YTF fields within these plays in the Malay Basin could be significant, based upon fractal and creaming curve analysis, augmented by the sequence stratigraphy that has been applied. Estimates for HCIIP and YTF resource will be presented during the Address. The exact size of the HCIIP is open to conjecture being that it is dependent within the mathematically-constrained geometric shape of the distribution curve, especially when calibrated to existing field sizes. As Niels Bohr, the Quantum Physicist, once said "It is very difficult to make an accurate prediction, especially about the future." In our business it is the same. Predicting YTF resources and where to find them is a challenge; and the challenge is met by the crystal ball of sequence-stratigraphy. If used correctly, sequence analysis in a stratigraphic context has, and can in the Malay Basin, prove up where fractal distribution YTF resources will be located. So throw your dice away. It is pleasure to present this Keynote Address to you. And I hope the contents have suggested some ideas which will help you to discover large reserves.
-
-
-
Formula for Success: The Role of New Information in Creating Asset Value
More LessA challenge that faces all asset managers is when and how much to invest in new information (e.g., seismic or well log data) to gain a more detailed image or knowledge of their reservoir. In Malaysia this can be a particularly vexing question in late field life when revenues are declining and there is a need to boost production through further infill drilling. Yet it is precisely in this situation, where there is great uncertainly about whether to drill and where to drill, that more detailed knowledge of the reservoir can contribute the most value. Similarly, improvements in reservoir characterization and imaging can significantly contribute to the success of deepwater dev elopments where template slots are sparse and productivity of each development well directly impacts the field’s return on investment (ROI). Often, better measurements are provided through technology innovation. The seismic industry has a proven track record in continuously innovating new technologies, such as single–sensor seismic recording (e.g. Q-Marine♦ technology) for repeatable time-lapse seismic or new depth-imaging techniques. The benefits of these technology developments are observed in the seismic data in the form of improved resolution of thin beds, better imaging beneath salt and basalt horizons, and, in the case of time-lapse seismic, snapshots of reservoir production, to name but a few examples. Some companies such as Petronas recognise the added-value impact of technology to its business competitiveness and sustained growth. However the industry is generally viewed as being slower than other industries to adopted new technologies even though they bring the prospect of better reservoir understanding and better well placement. We can ask the question, why is this so? One reason may be culture; as an industry we are focused on risk mitigation and new technologies are perceived as risky. New technologies are trialled initially by innovators and early adopters, these people are generally visionaries and risk takers, however the majority will not adopt until the value of the technology is proven. The other reason and that which concerns this paper, is that the value information brings is inherently difficult to predict. How do we predict the value of information? Well first we must understand what drives
and influences information gathering.
-
-
-
Global Carbonate Perspectives – Past, Present and Future Scenarios
More LessStatistic on worldwide reserves shows that about 60% of the remaining 1,212.8 billion bbl of the world’s oil and 5,501.1 Tcf of gas reserves are trapped within different ages of carbonate reservoirs. By geographical regions, Middle East contributes the highest percentage of carbonate reservoirs that accumulate 675.7 billion bbl of oil and 1,749.3 Tcf of gas. This area has so far generated 31 super giant (exceed 5 billion bbl proved reserve) and 60 giant (1-5 billion bbl proved reserve) oil and gas fields that make the region critically very important for oil and gas industry. Ghawar field in Saudi Arabia (the world largest oil field discovered in 1948 with a proved reserve of 200 billion bbl) and the North gas field in Qatar/Iran (the world largest gas field with over 800 Tcf proved reserve) are located in this region. The Eastern Europe, Caspian and FSU countries namely Azerbajan, Kazakstan and part of Russia have a total proved hydrocarbon reserve of over 26 billion bbl from carbonates. They are followed by the western hemisphere mainly Northern America, Canada, Mexico, and part of northern South America that have trapped 14.76 billion bbl of oil within the carbonates. An additional 6.59 billion bbl of oil come from northern Africa that mainly contributed by several carbonate formations in Libya and Egypt. Southeast Asian countries and Australia have contributed about 2.5 billion bbl of oil and gas from their carbonate reservoirs. These statistics obviously indicate that the carbonates remain exceptionally very important for oil and gas exploration and development despite many recent discoveries made in deepwater siliciclastic plays.
-