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PGCE 2006
- Conference date: 27 Dec 2006 - 28 Dec 2006
- Location: Kuala Lumpur, Malaysia
- Published: 27 November 2006
51 - 60 of 60 results
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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.
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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).
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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