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Статті в журналах з теми "Core parameters; hydrocarbon basins"
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Alarcón Olave, Helmer Fernando, and Edwar Hernando Herrera Otero. "Petrophysical properties of bypassed Cenozoic clastic reservoirs in the Cesar sub-basin, Colombia." Earth Sciences Research Journal 25, no. 3 (October 27, 2021): 275–84. http://dx.doi.org/10.15446/esrj.v25n3.89293.
Повний текст джерелаАнотація:
The Cesar-Ranchería basin has all the necessary elements for the generation, expulsion, and migration of hydrocarbons and considerable potential for coal bed methane (CBM) in Colombia. Previous studies in the Cesar basin focused on understanding the tectonic evolution, stratigraphy, hydrocarbon generation potential, and evaluation of reservoir potential in Cretaceous calcareous units and quartzose sandstones from the Paleocene Barco Formation. These studies had confirmed the existence of an effective petroleum system, with several episodes of oil expulsion and re-emigration in the Miocene period, turning the Cenozoic clastic succession (Barco, Los Cuervos, La Loma, and Cuesta formations) into an element of significant exploratory interest to clarify the potentiality of the basin in terms of hydrocarbon accumulation. The petrophysical parameters of Cenozoic units (shale volume, porosity, water, and oil saturation) were determined by integrating wells log and core samples analyses from three stratigraphic wells. The integration of these results synthesizes the petrophysical behavior of the units. It defines intervals with clay volumes of less than 30%, effective porosity around 20%, which means favorable characteristics as reservoir rocks that need to be considered in future exploratory projects.
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Farhaduzzaman, M., MA Islam, WH Abdullah, and J. Dutta. "Log based petrophysical analysis of mio-pliocene sandstone reservoir encountered in well Rashidpur 4 of Bengal Basin in Bangladesh." Bangladesh Journal of Scientific and Industrial Research 51, no. 1 (March 28, 2016): 23–34. http://dx.doi.org/10.3329/bjsir.v51i1.27032.
Повний текст джерелаАнотація:
Rashidpur is located in the northeastern part of Bangladesh which is surrounded on three sides by India and on a small portion by Myanmar. Gamma-ray, spontaneous potential, density, neutron, resistivity, caliper, temperature and sonic logs are used to analyze petrophysical parameters of the well Rashidpur 4, Bangladesh. Quantitative measurements of different factors such as shale volume, porosity, permeability, water saturation, hydrocarbon saturation and bulk volume of water are carried out using well logs. Petrographic and XRD results based on several core samples are also compared with log-derived parameters. Twenty permeable zones are identified whereby four are hydrocarbon bearing in the studied Mio-Pliocene reservoir sandstones. Measured shale volume ranges from 11% to 38% and porosity is 19% to 28%. However, log-derived porosity is slightly higher than the thin section porosity. Water saturation of the interested zones varies from 14% to 38%, 13% to 39% and 16% to 41% measured from Schlumberger, Fertl and Simandoux formula respectively. Conversely, hydrocarbon saturation of the examined hydrocarbon zones ranges from 62% to 86%, 61% to 83% and 59% to 84% respectively. In the analyzed zones, the permeability values are calculated as 28-305 mD. Good to very good quality hydrocarbon reservoirs are appraised for the studied four zones based on the petrophysical parameters, petrographic observation and XRD analysis. Among these, Zone 4 is the best quality reservoir for hydrocarbon.Bangladesh J. Sci. Ind. Res. 51(1), 23-34, 2016
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Sun, Yu, Lingling Liao, Shuyong Shi, Jinzhong Liu, and Yunpeng Wang. "How TOC affects Rock-Eval pyrolysis and hydrocarbon generation kinetics: an example of Yanchang Shale (T3y) from Ordos Basin, China." IOP Conference Series: Earth and Environmental Science 600, no. 1 (November 1, 2020): 012026. http://dx.doi.org/10.1088/1755-1315/600/1/012026.
Повний текст джерелаАнотація:
Abstract Rock-Eval pyrolysis and kinetics are widely used to evaluate hydrocarbon generations. Due to heterogeneity of shale, even a series of samples come from the same drill core rock will have a wide range of total organic carbon (TOC). It is important to select propriate TOC samples to acquire Rock-Eval and kinetic parameters. However, influence of different TOC levels to Rock-Eval and kinetics are still not well known. In this study, different samples with different TOC of 3.87%, 13.59%, 18.17%, 23.93%, 25.93% and 35.35% taken from one drill core were selected and analysed. And all samples are prepared to 4mm grain-size samples for Rock-Eval pyrolysis to reflect hydrocarbon generation and expulsion in realistic conditions. The results show that generation rate gradually decreases from 0.0064 to 0.0053 mg/g·s−1 when TOC increase from 13.59 to 35.35%. And the samples with 35.35% and 25.53% TOC show highest transformation ratio, while the samples with 3.87% show the lowest transformation ratio. In addition, the samples with 3.87% TOC only shows one main activation energy peak (56Kcal/mol). Yet the samples with 35.35% TOC shows three activation energy peaks (53, 54, 56Kcal/mol). With increasing of TOC levels of samples, percentage of main activation energy decrease from 69.43 to 25.96 and 29.62%. Therefore, generation rate of high TOC shale will decrease and transformation ratio will increase. And hydrocarbon generation and expulsion of high TOC samples need lower action energies.
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Lüning, Sebastian, Sadat Kolonic, David K. Loydell, and Jonathan Craig. "Reconstruction of the original organic richness in weathered Silurian shale outcrops (Murzuq and Kufra basins, southern Libya)." GeoArabia 8, no. 2 (April 1, 2003): 299–308. http://dx.doi.org/10.2113/geoarabia0802299.
Повний текст джерелаАнотація:
ABSTRACT The early Silurian in North Africa and Arabia was characterised by widespread deposition of organic-rich shales in palaeo-depressions. The unit represents an important hydrocarbon source rock in the region and can be detected easily in well logs because of strong uranium-related natural radiation. In exposures, however, organic matter is commonly heavily oxidised through weathering so that identification of the unit in the field is difficult. Uranium and pyrite framboids appear to be less vulnerable to weathering and may be used to identify intervals of originally organic-rich shales in exposures. Framboids are discrete spheroidal aggregates of pyrite microcrystallites and their size distribution is thought to be controlled by palaeo-depositional bottom-water redox-conditions. Analyses of fresh Silurian organic-rich shales from a core reveal a close correspondence, for the most part, between total organic carbon, total gamma-ray response, uranium content (as determined by spectral gamma-ray) and framboid parameters. Feasibility tests of the concept have been carried out at two exposures in southern Libya and may form the basis for improved Silurian organic-rich shale distribution maps and more precise age models for Silurian organic-rich depositional phases in northern Gondwana.
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Woillez, Marie-Noëlle, Christine Souque, Jean-Luc Rudkiewicz, Françoise Willien, and Tristan Cornu. "Insights in Fault Flow Behaviour from Onshore Nigeria Petroleum System Modelling." Oil & Gas Sciences and Technology – Revue d’IFP Energies nouvelles 72, no. 5 (September 2017): 31. http://dx.doi.org/10.2516/ogst/2017029.
Повний текст джерелаАнотація:
Faults are complex geological features acting either as permeability barrier, baffle or drain to fluid flow in sedimentary basins. Their role can be crucial for over-pressure building and hydrocarbon migration, therefore they have to be properly integrated in basin modelling. The ArcTem basin simulator included in the TemisFlow software has been specifically designed to improve the modelling of faulted geological settings and to get a numerical representation of fault zones closer to the geological description. Here we present new developments in the simulator to compute fault properties through time as a function of available geological parameters, for single-phase 2D simulations. We have used this new prototype to model pressure evolution on a siliciclastic 2D section located onshore in the Niger Delta. The section is crossed by several normal growth faults which subdivide the basin into several sedimentary units and appear to be lateral limits of strong over-pressured zones. Faults are also thought to play a crucial role in hydrocarbons migration from the deep source rocks to shallow reservoirs. We automatically compute the Shale Gouge Ratio (SGR) along the fault planes through time, as well as the fault displacement velocity. The fault core permeability is then computed as a function of the SGR, including threshold values to account for shale smear formation. Longitudinal fault fluid flow is enhanced during periods of high fault slip velocity. The method allows us to simulate both along-fault drainages during the basin history as well as overpressure building at present-day. The simulated pressures are at first order within the range of observed pressures we had at our disposal.
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Ruppel, Stephen C., Harry Rowe, Kitty Milliken, Chao Gao, and Yongping Wan. "Facies, rock attributes, stratigraphy, and depositional environments: Yanchang Formation, Central Ordos Basin, China." Interpretation 5, no. 2 (May 31, 2017): SF15—SF29. http://dx.doi.org/10.1190/int-2016-0122.1.
Повний текст джерелаАнотація:
The Late Triassic Yanchang Formation (Fm) is a major target of drilling for hydrocarbons in the Ordos Basin. Although most of the early focus on this thick succession of lacustrine rocks has been the dominant deltaic sandstones and siltstones, which act as local reservoirs of oil and gas, more recent consideration has been given to the organic-rich mudstone source rocks. We used modern chemostratigraphic analysis to define vertical facies successions in two closely spaced cores through the Chang 7 Member, the primary source rock for the Yanchang hydrocarbon system. We used integrated high-resolution X-ray fluorescence and X-ray diffraction measurements to define four dominant facies. Variations in stable carbon isotopes mimic facies stacking patterns, suggesting that terrigenous organic matter (although minor in volume) is associated with the arkoses and sandstones, whereas aquatic organic matter is dominant in the mudstones. Facies stacking patterns define three major depositional cycles and parts of two others, each defined by basal mudstone facies that document basin flooding and deepening (i.e., flooding surfaces). Unconfined compressive strength measurements correlate with clay mineral abundance and organic matter. Comparisons of core attributes with wireline logs indicate that although general variations in clay mineral volumes (i.e., mudstone abundance) can be discerned from gamma-ray logs, organic-matter distribution is best defined with density or resistivity logs. These findings, especially those established between the core and log data, provide a powerful linkage between larger scale facies patterns and smaller scale studies of key reservoir attributes, such as pore systems, mineralogy, diagenesis, rock mechanics, hydrocarbon saturation, porosity and permeability, and flow parameters. This first application of modern chemostratigraphic techniques to the Yanchang Fm reveals the great promise of applying these methods to better understand the complex facies patterns that define this lacustrine basin and the variations in key reservoir properties that each facies displays.
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J. Sunday, Abe, and Lurogho S. Ayoleyi. "Petrophysical analysis of “explorer” wells using well log and core data(a case study of “explorer” field, offshore Niger Delta, Nigeria)." International Journal of Advanced Geosciences 8, no. 2 (October 22, 2020): 219. http://dx.doi.org/10.14419/ijag.v8i2.31114.
Повний текст джерелаАнотація:
Reservoir characterization involves computing various petrophysical parameters and defining them in terms of their quantity and quality so as to ascertain the yield of the reservoir. Petrophysical well log and core data were integrated to analyze the reservoir characteristics of Explorer field, Offshore, Niger Delta using three wells. The study entails determination of the lithology, shale volume (Vsh), porosity (Φ), permeability (K), fluid saturation and cross plotting of petrophysical and core values at specific intervals to know their level of correlation. The analysis identified twelve hydrocarbon-bearing reservoir from three different wells. Average permeability value of the reservoir is 20, 0140md while porosity value range between 18% to 39%. Fluid type defined in the reservoirs on the basis of neutron/density log signature were basically water, oil and gas, low water saturation values ranging from 2.9% to 46% in Explorer wells indicate high hydrocarbon saturation. The Pearson Correlation Coefficient and Regression Equation gave a significant relationship between petrophysical derived data and core data. Scatter plot of petrophysical gamma ray values versus core gamma ray values gave an approximate linear relationship with correlation coefficient values of 0.6642, 0.9831 and 0.3261. Crossplot of petrophysical density values and core density values revealed that there is a strong linear relationship between the two data set with correlation coefficient values of 0.7581, 0.9872 and 0.3557, and the regression equation confirmed the relationship between the two data set. Also the scatter plot of petrophysical porosity density values versus core porosity density values revealed a strong linear relationship between the two data set with correlation coefficient values of 0.7608 and 0.9849, the regression equation confirmed this also. Crossplot of petrophysical porosity density values versus core porosity density values in Well 3 gave a very weak correlation coefficient values of 0.3261 and 0.3557 with a negative slope. The petrophysical properties of the reservoirs in Explorer Well showed that they contain hydrocarbon in commercial quantity and the cross plot of the petrophysical and core values showed direct relationship in most of the wells.
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Kosakowski, Paweł, Dariusz Więcław, Adam Kowalski, and Yuriy Koltun. "Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine)." Geologica Carpathica 63, no. 4 (August 1, 2012): 319–33. http://dx.doi.org/10.2478/v10096-012-0025-3.
Повний текст джерелаАнотація:
Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine) The Jurassic/Cretaceous stratigraphic complex forming a part of the sedimentary cover of both the eastern Małopolska Block and the adjacent Łysogóry-Radom Block in the Polish part as well as the Rava Rus'ka and the Kokhanivka Zones in the Ukrainian part of the basement of the Carpathian Foredeep were studied with geochemical methods in order to evaluate the possibility of hydrocarbon generation. In the Polish part of the study area, the Mesozoic strata were characterized on the basis of the analytical results of 121 core samples derived from 11 wells. The samples originated mostly from the Middle Jurassic and partly from the Lower/Upper Cretaceous strata. In the Ukrainian part of the study area the Mesozoic sequence was characterized by 348 core samples collected from 26 wells. The obtained geochemical results indicate that in both the south-eastern part of Poland and the western part of Ukraine the studied Jurassic/Cretaceous sedimentary complex reveals generally low hydrocarbon source-rock potential. The most favourable geochemical parameters: TOC up to 26 wt. % and genetic potential up to 39 mg/g of rock, were found in the Middle Jurassic strata. However, these high values are contradicted by the low hydrocarbon index (HI), usually below 100 mg HC/g TOC. Organic matter from the Middle Jurassic strata is of mixed type, dominated by gas-prone, Type III kerogen. In the Polish part of the study area, organic matter dispersed in these strata is generally immature (Tmax below 435 °C) whereas in the Ukrainian part maturity is sufficient for hydrocarbon generation.
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Thota, Surya Tejasvi, Md Aminul Islam, and Mohamed Ragab Shalaby. "A 3D geological model of a structurally complex relationships of sedimentary Facies and Petrophysical Parameters for the late Miocene Mount Messenger Formation in the Kaimiro-Ngatoro field, Taranaki Basin, New Zealand." Journal of Petroleum Exploration and Production Technology 12, no. 4 (November 21, 2021): 1147–82. http://dx.doi.org/10.1007/s13202-021-01366-0.
Повний текст джерелаАнотація:
AbstractThe present study investigates the reservoir characteristics of the Mount Messenger Formation of Kaimiro-Ngatoro Field which was deposited in deep-water environment. A 3D seismic dataset, core data and well data from the Kaimiro-Ngatoro Field were utilized to identify lithofacies, sedimentary structures, stratigraphic units, depositional environments and to construct 3D geological models. Five different lithologies of sandstone, sandy siltstone, siltstone, claystone and mudstone are identified from core photographs, and also Bouma sequence divisions are also observed. Based on log character Mount Messenger Formation is divided into two stratigraphic units slope fans and basin floor fans; core analysis suggests that basin floor fans show better reservoir qualities compared to slope fan deposits. Seismic interpretation indicates 2 horizons and 11 faults, majority of faults have throw less than 10 m, and most of the faults have high angle dips of 70–80°. The Kaimiro and Ngatoro Fields are separated by a major Inglewood fault. Variance attribute helped to interpret faults, and other seismic attributes such as root-mean-square amplitude, envelope and generalized spectral decomposition also helped to detect hydrocarbons. The lithofacies model was constructed by using sequential simulation indicator algorithm, and the petrophysical models were constructed using sequential Gaussian simulation algorithm. The petrophysical parameters determined from the models comprised of up to ≥ 25% porosity, permeability up to around 600mD, hydrocarbon saturation up to 60%, net to gross varies from 0 to 100%, majority of shale volumes are around 15–20%, the study interval mostly consists of macropores with some megapores and 4 hydraulic flow units. This study best characterizes the deep-water turbidite reservoir in New Zealand.
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Thul, David, and Stephen Sonnenberg. "Expression of the Colorado Mineral Belt in Upper Cretaceous Niobrara Formation Source Rock Maturity Data from the Denver Basin." Mountain Geologist 55, no. 1 (January 2018): 19–52. http://dx.doi.org/10.31582/rmag.mg.55.1.19.
Повний текст джерелаАнотація:
New source rock maturity data along the Colorado Mineral Belt trend in the Denver Basin reveal that source rocks in the deepest portion of the basin range from the onset of oil generation to wet gas maturity across a distance of less than 30 miles along present day structure. Additionally, sampled rock core and cuttings along a northeast-southwest transect reveal that the Niobrara Formation is within the oil maturity window all the way to the Nebraska-Colorado border. The correlation of these analyses to an identified thermal anomaly demonstrate that maturity along these trends is affected by a historical increase in heat flow that can still be seen in the present-day bottom-hole temperatures. The identified maturity anomaly has significant implications for Niobrara prospectivity within the basin. Crossplotting, mapping, and numerical modeling show the onset of hydrocarbon maturity in the Niobrara is represented by 432 °C Tmax and that hydrocarbon expulsion occurs between 438 °C and 443 °C Tmax. In the Niobrara Formation of the Denver Basin there is a strong correlation between oil and gas shows, elevated bottom-hole temperatures (and thermal gradients), and geochemical maturity parameters. Through mapping of maturity and free hydrocarbon anomalies, more than 80% of the present day production can be predicted with source rock mapping.
Дисертації з теми "Core parameters; hydrocarbon basins"
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Goda, Hussam M. "Prediction of special core parameters for Australian hydrocarbon basins." Thesis, 2006. http://hdl.handle.net/2440/74882.
Повний текст джерелаАнотація:
The determination, validation and understanding, and proper use of special core analysis relationships are paramount in the assessment of recovery efficiency of petroleum reservoirs. The most reliable information, resulting in representative relationships, such as for relative permeability and capillary pressure, may be obtained from laboratory experiments. However, being time-consuming and expensive, the number of core samples typically subjected to such investigations tends to be limited, often resulting in data deficiencies and hence improper understanding of the necessary relationships, which are essential for conducting detailed reservoir engineering and simulation studies, with the aim of maximising the extraction of petroleum. For the above reasons, over the past decades, the establishment of mathematical models to predict the required properties has received considerable attention from petroleum engineers, and is one of the active research areas today.
In an attempt to predict valid relationships, difficulties are primarily related to complexity and variability of rocks, in terms of pore structure and mineralogy and associated fundamental properties: porosity, absolute permeability, and fluid saturation. Such variation is a function of the original deposition of grains and subsequent alteration or diagenesis of a geological formation, most notably rock. compaction upon burial, but also other significant alteration, for example the generation of different types of clays, filling part of the pore structure. In addition to pore structure variation, the second complication is associated with the surface chemistry between fluids and the varied rock grains, as well as the interaction between fluids themselves, for example oil and water contained in the pores. Thirdly, in conducting laboratory experiments, the precise experimental conditions may greatly influence results obtained: pressure, temperature and the types of fluids used and their properties, most notably fluid viscosity, flow velocity and interfacial tension. Investigations by co-researchers and others into single-phase flow and the identification of appropriate geological entities, or facies, representative of (homogeneous) flow behaviour, have led to the conclusion that the Carman-Kozeny model is ideally suited to bridge the gap between the differing views of geologists and engineers. As this model is able to elegantly unify the parameters for single phase flow for the majority of petroleum rocks, the formulation was subsequently extended to two phase flow situations by the principal supervisor. These concepts were then utilised in this research and further extended, and a number of new relationships were established, which may be used to validate experimental data and relationships or predict such relationships from more fundamental properties. In deriving the above formulations, an extensive database was utilised, semi-empirically fitting the data for establishing some of the relationships. In other cases the data was used to validate new models, comparing model-generated and experimental results. The database was created by utilising laboratory data generated by commercial laboratories and made available by several petroleum companies, covering onshore and offshore Australian hydrocarbon basins. Both, capillary pressure and relative permeability models were validated using this data, and the new models were demonstrated to have excellent performance in predicting two-phase flow relationships. In a further attempt to validate these models, comparison studies were also conducted with well-known models used by the oil and gas industry. The Brooks and Corey capillary pressure model was used for comparison with the newly established capillary pressure model, and the performance of the new relative permeability model was checked against that of the modified Brook and Corey model, also known as the power law model. Relative permeability and capillary pressure models depend on the primary parameters mentioned above but are actually formulated in terms of several secondary parameters, functions of primary parameters. As such irreducible water saturation is most significant. If this quantity has not been measured in the laboratory, it may be predicted. New models were established to predict irreducible water saturation, based on an artificial neural network approach. A semi-empirical model, based on trapping parameters, was also investigated, resulting in an alternate formulation for irreducible water saturation, and a universal analytical form that should be applicable to the range of geological formations. As mentioned above, relative permeability relationships are also controlled by wettability. For the purpose of predicting relative permeability, a new model to link the USBM wettability index to pore structure parameters was also established by this research. As with relative permeability, capillary pressure and irreducible water saturation models, the model was created and validated using the Australian database. However, the general form of the equation would lend itself for use with any data set. Finally, the ratio of effective (or relative) permeability endpoints may be taken as an indictor of wettability. Equations to predict effective permeability to oil at irreducible water saturation and effective permeability to water at residual oil saturation have been formulated. Both equations are extensions of the Carman-Kozeny formulation.Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2006
Тези доповідей конференцій з теми "Core parameters; hydrocarbon basins"
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Jarassova, Tolganay, and Mehmet Altunsoy. "Organic Geochemical Characteristics of Core Samples from Central Primorsk-Emba Province, Precaspian Basin, Kazakhstan." In SPE Annual Caspian Technical Conference. SPE, 2021. http://dx.doi.org/10.2118/207044-ms.
Повний текст джерелаАнотація:
Abstract The Primorsk-Emba province is one of the main oil and gas region of the Precaspian basin. The resources of the Primorsk-Emba oil and gas region range from 5 to 12 billion tons of oil and from 2 to 6 trillion m³ of natural gas. This study primarily concentrates on investigating the organic geochemistry and petroleum geology characteristics of sedimentary units that generated oil in the central Primorsk-Emba province. 20 core samples taken from the Jurassic units in the western part of the study area are characterized by organic matter amount, hydrocarbon production potential, type of organic matter, maturity of organic matter. According to the Rock-Eval results Jurassic aged rocks generally have a petroleum potential ranging from weak to excellent, the organic matter is between Type II (oil prone), Type II-III (gas-oil prone) and Type III (gas prone), and the degree of maturation is immature-mature stage. Oil extracts were characterized by geochemical methods including Gas Chromatography (GC) and Gas Chromatography–Mass Spectrometry (GC–MS). n-alkanes and isoprenoids were evaluated by High-Resolution Gas Chromatography (GC-HR), aromatic hydrocarbons were evaluated by Low Thermal Mass Gas Chromatography (GC-LTM), terpanes (hopanes), steranes / diasteranes and aromatic hydrocarbons were evaluated by Gas Chromatography-Mass Spectrometry (GC-MS). The GC and GC-MS data obtained, it has been determined whether the paleoenvironment characteristics of the study area, hydrocarbon potential, type of kerogen, maturity level of organic matter and whether it is affected by biodegradation. Distribution of n-alkanes in the GC showed that no biodegradation was observed in analyzed samples, source rock deposited in a marine environment under reducing conditions and an organic matter that occurred were generated by marine carbonates. Based on maturity parameters, studied oils are mature and located on the oil generation window. According to biomarker age parameters C28 / C29 and norcholestane (NCR)/nordiacholestane (NDR) samples are generally Mesozoic (Triassic-Jurassic- Cretaceous) origin, nevertheless there are also levels corresponding to the Paleozoic (Permian) late stages.
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Jarassova, Tolganay, and Mehmet Altunsoy. "Organic Geochemical Characteristics of Core Samples from Central Primorsk-Emba Province, Precaspian Basin, Kazakhstan." In SPE Annual Caspian Technical Conference. SPE, 2021. http://dx.doi.org/10.2118/207044-ms.
Повний текст джерелаАнотація:
Abstract The Primorsk-Emba province is one of the main oil and gas region of the Precaspian basin. The resources of the Primorsk-Emba oil and gas region range from 5 to 12 billion tons of oil and from 2 to 6 trillion m³ of natural gas. This study primarily concentrates on investigating the organic geochemistry and petroleum geology characteristics of sedimentary units that generated oil in the central Primorsk-Emba province. 20 core samples taken from the Jurassic units in the western part of the study area are characterized by organic matter amount, hydrocarbon production potential, type of organic matter, maturity of organic matter. According to the Rock-Eval results Jurassic aged rocks generally have a petroleum potential ranging from weak to excellent, the organic matter is between Type II (oil prone), Type II-III (gas-oil prone) and Type III (gas prone), and the degree of maturation is immature-mature stage. Oil extracts were characterized by geochemical methods including Gas Chromatography (GC) and Gas Chromatography–Mass Spectrometry (GC–MS). n-alkanes and isoprenoids were evaluated by High-Resolution Gas Chromatography (GC-HR), aromatic hydrocarbons were evaluated by Low Thermal Mass Gas Chromatography (GC-LTM), terpanes (hopanes), steranes / diasteranes and aromatic hydrocarbons were evaluated by Gas Chromatography-Mass Spectrometry (GC-MS). The GC and GC-MS data obtained, it has been determined whether the paleoenvironment characteristics of the study area, hydrocarbon potential, type of kerogen, maturity level of organic matter and whether it is affected by biodegradation. Distribution of n-alkanes in the GC showed that no biodegradation was observed in analyzed samples, source rock deposited in a marine environment under reducing conditions and an organic matter that occurred were generated by marine carbonates. Based on maturity parameters, studied oils are mature and located on the oil generation window. According to biomarker age parameters C28 / C29 and norcholestane (NCR)/nordiacholestane (NDR) samples are generally Mesozoic (Triassic-Jurassic- Cretaceous) origin, nevertheless there are also levels corresponding to the Paleozoic (Permian) late stages.
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"Low Resistivity Reservoir Pay Evaluation, New Opportunity for Further Development, Case Study On Gumai Formation Of B Field, Jambi Sub Basin, South Sumatera Basin." In Indonesian Petroleum Association 44th Annual Convention and Exhibition. Indonesian Petroleum Association, 2021. http://dx.doi.org/10.29118/ipa21-se-128.
Повний текст джерелаАнотація:
The understanding of low resistivity reservoir zone is one of the most challenging cases for further development in order to optimize the remaining oil and gas field productions. In the Intra-Gumai Formation “B” Field where marine clastic reservoirs are deposited, a low resistivity reservoir is being developed as a new perforation and workover target. This study discusses how to identify the cause of low resistivity case and evaluate the proper petrophysical parameters to unlock the potential reservoir pay zones. The data set consists of petrographic, X-Ray Diffraction (XRD), Cation Exchange Capacity (CEC), routine core, Drill Stem Test ((DST) and wireline logs data. Petrographic, XRD, CEC and routine analysis were performed to recognize the low resistivity causes characterized by the presence of framework grain (quartz, K-feldspar and glaucony, calcite and kaolinite) observed in intergranular pore and also quartz overgrowth developed prior to kaolinite precipitation. Petrophysical analysis defines the reservoir property parameters by comparing some equations also validated with routine core and DST result. Based on the quantitative analysis carried out, namely the evaluation of the distribution of shale volume, calculation of porosity, and determination of water saturation, it is recommended to use the Stieber method for the distribution of shale volume in the reservoir and its properties, the neutron density porosity method to calculate porosity model, and the Waxman Smits method to determine the final fluid saturation model. Finally, by using the hydrocarbon saturation results in the current study, this interval was improved as pay zone. This method will be applied to other wells and other structures that have a similar depositional environment to increase hydrocarbon reserves in the same field.
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Tolioe, William Amelio, Linda Hanalim, Joely Bt A Ghafar, and Thanapala Singam Murugesu. "Integrated Advance Petrophysical Evaluation for Heterolithic Clastics Reservoir Characterization Optimization in Malay Basin." In Offshore Technology Conference Asia. OTC, 2022. http://dx.doi.org/10.4043/31452-ms.
Повний текст джерелаАнотація:
Abstract In an oil producing S-field within Malay basin, the existence of heterolithic and thinly laminated reservoirs are common. Standard resolution logging tools are incapable to separate inter-bedded sand-shale layers due to their low vertical resolutions and the conventional petrophysical workflow was not robust enough in capturing the actual properties of the laminated sand shale (LSS) reservoirs in S-field. As a result, the estimated permeability did not match the core permeability and required a significantly high multipliers in the dynamic model and the calculated saturation failed to match the Dean-Stark saturation. This paper explains the limitation of the conventional analysis in LSS reservoir and highlights the use of PETRONAS Thin Bed Analysis (TBA) module to estimate the actual reservoir properties in S-field. The case study in this paper shows the best practice to construct the robust fieldwide evaluation of reservoir properties, integrating core to production data and advance logs information, to determine reservoir properties. In LSS reservoirs, the conventional petrophysics outputs are often pessimistic compared to core data. Reservoir Enhancement Modeling and Reservoir Fraction Modeling (REM-RFM) is an in-house PETRONAS TBA methodology for evaluating LSS reservoirs. REM-RFM workflow is designed to obtain the net sand fraction and the actual reservoir properties to describe the reservoirs storage and flow capacity. Sand-shale lamination was quantified by digital core analysis, core UV light binning against the borehole image logs. The triaxial resistivity logs were used as inputs for the Thomas-Stieber method to determine the net sand fraction and the hydrocarbon saturation. Nuclear Magnetic Resonance (NMR) data was also incorporated to confirm the hydrocarbon pore volume on well level. The REM-RFM workflow resulted in the improved reservoir properties compared to the conventional evaluation and were better matched to the core. In the laminated sands, the enhanced shale volume was comparable to the sand streaks seen in UV fluorescence core photo and image logs data, as well the enhanced porosity and permeability were matching well with the core data. Moreover, the water saturation was matching to the saturation from dean-stark core analysis result, comparable to saturation height function model and NMR data, and REM-RFM output were comparable to Thomas-Stieber results. Once the REM-RFM was calibrated in the key wells, the parameters were then applied to the whole field. The in-house REM-RFM module discussed in this paper is an excellent addition to other industry methodologies. This module is basically a continuation of the innovative effort to characterize the conventional clastic reservoirs model performed earlier. It has been proven by applying robust evaluation, the conventional outputs are significantly improved that led to the optimizes the obvious volume of hydrocarbon estimated. In addition to that, the results can be used for reducing the risks in monetizing the opportunities from the heterolithics and laminated sands.
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Dash, Sabyasachi, and Zoya Heidari. "ENHANCED ASSESSMENT OF FLUID SATURATION IN THE WOLFCAMP FORMATION OF THE PERMIAN BASIN." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0052.
Повний текст джерелаАнотація:
Conventional resistivity models often overestimate water saturation in organic-rich mudrocks and require extensive calibration efforts. Conventional resistivity-porosity-saturation models assume brine in the formation as the only conductive component contributing to resistivity measurements. Enhanced resistivity models for shaly-sand analysis include clay concentration and clay-bound water as contributors to electrical conductivity. These shaly-sand models, however, consider the existing clay in the rock as dispersed, laminated, or structural, which does not reliably describe the distribution of clay network in organic-rich mudrocks. They also do not incorporate other conductive minerals and organic matter, which can significantly impact the resistivity measurements and lead to uncertainty in water saturation assessment. We recently introduced a method that quantitatively assimilates the type and spatial distribution of all conductive components to improve reserves evaluation in organic-rich mudrocks using electrical resistivity measurements. This paper aims to verify the reliability of the introduced method for the assessment of water/hydrocarbon saturation in the Wolfcamp formation of the Permian Basin. Our recently introduced resistivity model uses pore combination modeling to incorporate conductive (clay, pyrite, kerogen, brine) and non-conductive (grains, hydrocarbon) components in estimating effective resistivity. The inputs to the model are volumetric concentrations of minerals, the conductivity of rock components, and porosity obtained from laboratory measurements or interpretation of well logs. Geometric model parameters are also critical inputs to the model. To simultaneously estimate the geometric model parameters and water saturation, we develop two inversion algorithms (a) to estimate the geometric model parameters as inputs to the new resistivity model and (b) to estimate the water saturation. Rock type, pore structure, and spatial distribution of rock components affect geometric model parameters. Therefore, dividing the formation into reliable petrophysical zones is an essential step in this method. The geometric model parameters are determined for each rock type by minimizing the difference between the measured resistivity and the resistivity, estimated from Pore Combination Modeling. We applied the new rock physics model to two wells drilled in the Permian Basin. The depth interval of interest was located in the Wolfcamp formation. The rock-class-based inversion showed variation in geometric model parameters, which improved the assessment of water saturation. Results demonstrated that the new method improved water saturation estimates by 32.1% and 36.2% compared to Waxman-Smits and Archie's models, respectively, in the Wolfcamp formation. The most considerable improvement was observed in the Middle and Lower Wolfcamp formation, where the average clay concentration was relatively higher than the other zones. Results demonstrated that the proposed method was shown to improve the estimates of hydrocarbon reserves in the Permian Basin by 33%. The hydrocarbon reserves were underestimated by an average of 70000 bbl/acre when water saturation was quantified using Archie's model in the Permian Basin. It should be highlighted that the new method did not require any calibration effort to obtain model parameters for estimating water saturation. This method minimizes the need for extensive calibration efforts for the assessment of hydrocarbon/water saturation in organic-rich mudrocks. By minimizing the need for extensive calibration work, we can reduce the number of core samples acquired. This is the unique contribution of this rock-physics-based workflow.
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Masoud, Mohamed, W. Scott Meddaugh, Masoud Eljaroshi, and Khaled Elghanduri. "Enhanced and Rock Typing-Based Reservoir Characterization of the Palaeocene Harash Carbonate Reservoir-Zelten Field-Sirte Basin-Libya." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205971-ms.
Повний текст джерелаАнотація:
Abstract The Harash Formation was previously known as the Ruaga A and is considered to be one of the most productive reservoirs in the Zelten field in terms of reservoir quality, areal extent, and hydrocarbon quantity. To date, nearly 70 wells were drilled targeting the Harash reservoir. A few wells initially naturally produced but most had to be stimulated which reflected the field drilling and development plan. The Harash reservoir rock typing identification was essential in understanding the reservoir geology implementation of reservoir development drilling program, the construction of representative reservoir models, hydrocarbons volumetric calculations, and historical pressure-production matching in the flow modelling processes. The objectives of this study are to predict the permeability at un-cored wells and unsampled locations, to classify the reservoir rocks into main rock typing, and to build robust reservoir properties models in which static petrophysical properties and fluid properties are assigned for identified rock type and assessed the existed vertical and lateral heterogeneity within the Palaeocene Harash carbonate reservoir. Initially, an objective-based workflow was developed by generating a training dataset from open hole logs and core samples which were conventionally and specially analyzed of six wells. The developed dataset was used to predict permeability at cored wells through a K-mod model that applies Neural Network Analysis (NNA) and Declustring (DC) algorithms to generate representative permeability and electro-facies. Equal statistical weights were given to log responses without analytical supervision taking into account the significant log response variations. The core data was grouped on petrophysical basis to compute pore throat size aiming at deriving and enlarging the interpretation process from the core to log domain using Indexation and Probabilities of Self-Organized Maps (IPSOM) classification model to develop a reliable representation of rock type classification at the well scale. Permeability and rock typing derived from the open-hole logs and core samples analysis are the main K-mod and IPSOM classification model outputs. The results were propagated to more than 70 un-cored wells. Rock typing techniques were also conducted to classify the Harash reservoir rocks in a consistent manner. Depositional rock typing using a stratigraphic modified Lorenz plot and electro-facies suggest three different rock types that are probably linked to three flow zones. The defined rock types are dominated by specifc reservoir parameters. Electro-facies enables subdivision of the formation into petrophysical groups in which properties were assigned to and were characterized by dynamic behavior and the rock-fluid interaction. Capillary pressure and relative permeability data proved the complexity in rock capillarity. Subsequently, Swc is really rock typing dependent. The use of a consistent representative petrophysical rock type classification led to a significant improvement of geological and flow models.
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Panjaitan, J. "Novel Approach on Thin Bed Reservoir Case Study from Muda Formation, Natuna Basin." In Digital Technical Conference. Indonesian Petroleum Association, 2020. http://dx.doi.org/10.29118/ipa20-g-244.
Повний текст джерелаАнотація:
The presence of shale in thin beds reservoirs affects formation evaluation where the standard conventional log analyses are not designed to properly correct this effect. The conventional logging tools, with low vertical resolution, are not able to characterize these thin beds. This implies that log values do not represent the true bed or layer properties, but rather an average of multiple beds. Muda Formation are characterized by thin bed layers, made up of clastic rock sequences with dominant lithology of sandstone inter-bedded with shale, siltstone, and organic material as confirmed by drilling cuttings, logs response, and also supported by observation from sidewall cores. There are many uncertainties related to the presence of thin beds, primarily sand, silt, shale or their combination in term of their petrophysical properties and lateral extent. Inadequate reservoir characterization can cause significant amounts of oil and gas to remain unidentified. Accurate petrophysical parameters determination play an important role in the development plan of a field. The lateral and vertical variations in the petrophysical properties of the reservoir lead to different scenarios of the field development. The study of Muda Formation in this structure has integrated the sidewall core and log data. The contribution of the thin sand laminae to the average log response resulted in underestimating the porosity (Ф) and hydrocarbon saturation (Sh). The advanced measurement, like the resistivity anisotropy, proved quite useful as the vertical and horizontal resistivity across these beds leading to measurable electrical anisotropy. The resistivity measured perpendicular to the bedding is significantly higher than resistivity measured parallel to the bedding. The situation occurs due to high resistivity sand layers interbedded with low resistivity shale layers. The true sand porosity and hydrocarbon saturation were calculated using the laminated sand shale sequence and calibrated with core data. The study led to the more realistic petrophysical estimation of the sand shale laminae. A combination and integration of high-resolution image log for sand count, nuclear magnetic resonance (NMR) for porosity evaluation and triaxial resistivity for volumetric model through Laminated Sand Analysis approach are found useful to solve thin bed reservoir issue.
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Habib, Kashfi B., Andrew Cuff, and Tony King. "Analysis of Iceberg Frequency in Labrador Sea Using Aerial Reconnaissance Flight Surveys and Satellite Radar Data." In ASME 2015 34th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2015. http://dx.doi.org/10.1115/omae2015-42104.
Повний текст джерелаАнотація:
Recently Nalcor announced the discovery of three newly defined hydrocarbon basins located primarily in deep water in the Labrador Sea, off the east coast of Newfoundland and Labrador, Canada. The basins are Henley, Chidley and Holton Basins and expanded the extent of the Hawke Basin. On behalf of Nalcor Energy, C-CORE recently completed the Offshore Newfoundland and Labrador Metocean Study which summarizes environmental conditions of these regions to support offshore petroleum exploration and development in the Labrador Sea and to outline the resource potential to the global oil and gas industry. Defining iceberg densities was one of the required tasks for the study. Among various environmental conditions, iceberg density is one of the most challenging parameter to define accurately both spatially and temporally. Aerial iceberg reconnaissance flight surveys provided by IIP (International Ice Patrol) and CIS (Canadian Ice Service) were studied, classified and analyzed to compute iceberg density (number of icebergs per square km). Only open water icebergs were considered for analysis because of the difficulty associated with reliably identifying icebergs in pack ice, which may lead to an underestimation of iceberg occurrence. Therefore, aerial reconnaissance data were compared with CIS pack ice charts to eliminate any possibility of iceberg sightings in pack ice being included in the analysis. Satellite radar data acquired using Envisat wide swath mode (WSM) imagery was also used for iceberg detections in order to provide full coverage of the study area. Again, sea ice was outlined in the imagery to ensure no targets in sea ice were counted. The WSM imagery provided a 400 km wide swath with an approximate radar resolution of 150 m, meaning smaller targets were not detected. In order to combine satellite radar data with aerial reconnaissance surveys a non-detection factor was calculated using a comparison of concurrent Envisat and aerial coverage to compensate for missed targets due to the coarser radar resolution. The resulting map of open water iceberg densities will provide a baseline for the region which shall be further refined through an on-going program using high-resolution Sentinel satellite data. Detailed descriptions of the analysis, procedures and results are presented in this paper. Areal density results of the newly defined basins are compared to the other frontier regions, where iceberg risks are higher.
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Dash, Sabyasachi, and Zoya Heidari. "APPLICATION OF IMAGE LOGS FOR ENHANCED RESISTIVITY-BASED WATER SATURATION ASSESSMENT IN ORGANIC-RICH MUDROCKS." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0072.
Повний текст джерелаАнотація:
Organic-rich mudrocks are complex in terms of rock fabric (i.e., the spatial distribution of rock components), which impacts electrical resistivity measurements and, therefore, estimates of hydrocarbon reserves. Conventional resistivity-saturation-porosity methods for assessment of water/hydrocarbon saturation do not reliably incorporate the spatial distribution of rock components and pores in the assessment of fluid saturation. Extensive calibration efforts are required for indirectly projecting the impact of rock fabric on resistivity models. For instance, none of the existing shaly-sand models incorporate a realistic distribution of clay network. This might be acceptable in conventional reservoirs. However, oversimplifying assumptions can cause significant uncertainty in reserves evaluation in organic-rich mudrocks. It should be noted that even the methods which incorporate the realistic distribution of rock components are difficult to calibrate. To address the aforementioned challenge, we introduce a joint interpretation of conventional resistivity and resistivity image logs to improve water saturation assessment by honoring the type of rock component, the spatial distribution of the conductive and non-conductive rock components, and the volumetric concentration of fluids and minerals in the rock. Borehole image logs are a source of high-resolution continuous rock sequence records and can provide detailed rock-fabric-related features. In this paper, we propose a method for the estimation of lamination density and mean resistivity value from image logs within each rock type. These fabric-related features are used to quantify the geometric model parameters for each conductive component of the rock. We use these geometric model parameters as inputs to a new resistivity model that considers volumetric concentration and spatial distribution of rock components for a depth-by-depth assessment of water saturation. The other inputs to the workflow are the volumetric concentration of conductive and non-conductive rock components, electrical conductivity of rock components, and porosity estimates from the joint interpretation of well logs. We successfully applied the proposed workflow to a dataset from the Wolfcamp formation in the Permian Basin in which resistivity image logs were available. We observed a measurable variation in estimated image-log-based geometric model parameters, which were in agreement with the visual content of the images. Incorporation of the estimated rock-class-based geometric model parameters in the resistivity model improved water saturation assessment. Results demonstrated a relative improvement in water saturation estimates of 44.2% and 59.1% against Waxman-Smits and Archie's models, respectively. We then used the estimated geometric model parameters for each rock type for a depth-by-depth assessment of water saturation in one additional well without image logs. This led to a faster and more reliable assessment of water saturation within a certain distance from the well with image logs, where the rock types remain comparable. This distance can be evaluated using variogram analysis. We demonstrated that using the estimated geometric model parameters could improve estimates of hydrocarbon reserves in the Permian Basin by approximately 34%. It should be noted that the proposed method for assessment of geometric model parameters is completely based on the actual spatial distribution of rock components and does not require core-based calibration efforts.
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Sharma, Gaurav, and Derek Hayes. "Machine Learning Based Integrated Approach to Estimate Total Organic Carbon in Shale Reservoirs – A Case Study from Duvernay Formation, Alberta Canada." In SPE Canadian Energy Technology Conference. SPE, 2022. http://dx.doi.org/10.2118/208916-ms.
Повний текст джерелаАнотація:
Abstract Shale gas reservoirs have become prominent contributors to the world's hydrocarbon resources and production. They exhibit multiple storage mechanisms, two of which are linked to the free and adsorbed gas phase. Since the adsorbed gas may be stored as a denser phase than the free gas, the contribution of the adsorbed phase can be significant. The adsorbed volume is related to the total organic carbon (TOC) and thus, higher TOC can indicate higher hydrocarbon inplace. Furthermore, productivity can be linked to TOC through the potential for overpressure and conversion of kerogen to pore space. However, estimation of the TOC is not a trivial problem, as it depends on geological factors such as depositional environment. In this study, we propose an integrated workflow using concepts of machine learning to estimate TOC. The workflow is divided into 3 sections which are area selection, sub-region categorization, and prediction modeling. Firstly, 3 active exploration and development areas (Kaybob, Pembina, and East shale basin) of the Duvernay Formation are highlighted and the geology of each specific area is analyzed. Thereafter, using the available core data and average properties of the attributes (Gamma Ray, resistivity, density, and distance from mean vitrinite reflectance line), each area is clustered into sub-regions using SVM, logistic regression, and k-means clustering. Finally, using Random Forest prediction, models for each sub-region are developed and ranked with average mean square errors and standard deviations. It is observed that the Kaybob area can be clustered into 2 regions. This observation is supported by the principal component plot (PC1 vs PC2), which shows a dual cloud structure. This is further supported through clustering analysis, which also revealed the same observation. Results of the prediction modeling found random forest as the best predictor, achieving a match wiht the core data with a error less than 10% and in some cases only a 1% deviation. Shale reservoir characterization requires estimation of the key parameters such as TOC. However, it is difficult to estimate TOC with purely physics-based or purely statistical models, as it requires limited specialized data and is impacted by subtle variations in the reservoir. This study suggests that TOC can be accurately estimated by combining geological interpretation and machine learning based algorithms without bearing cost of the specialized data.