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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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DU, JIANGMIN, YANDE ZHAO, QINGCHUN WANG, YANQIU YU, HUI XIAO, XIANKUI XIE, YUGUO DU, and ZIMIAO SU. "Geochemical characteristics and resource potential analysis of Chang 7 organic-rich black shale in the Ordos Basin." Geological Magazine 156, no. 07 (December 19, 2018): 1131–40. http://dx.doi.org/10.1017/s0016756818000444.
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AbstractThe Ordos Basin is the largest and most important intracontinental sedimentary depression in China, and a significant amount of crude oil resources has developed within this Mesozoic formation. High-grade organic-rich shale is prevalent in the large-scale areas of the Chang 7 sedimentary stage and provides essential hydrocarbon resources for abundant oil enrichment in the Mesozoic. This research investigated the geochemical characteristics of Chang 7 shale using core samples and well logs and via laboratory tests. In addition, the microscopic components of the shale organic matter (OM), biological marker compounds, carbon isotopes, enrichment grade of trace elements, and elemental ratio were analysed systematically. Moreover, the aspects related to the shale OM source, sedimentary environment and resource potential were evaluated. Our results revealed that spherical alginate and calcium spherical alginate were predominant in the micropetrological components of the shale. Many biomarkers, including n-alkanes, steranes and terpanes, were detected in the gas chromatography – mass spectrometry spectra. An analysis of n-alkanes, regular sterane shapes (C21−/C22− and C26+C27/C28+C29), odd–even predominance index (OEP) and carbon preference index (CPI) values and carbon isotope distributions showed that OM was produced from aquatic organisms. The indicators of trace elements, such as Sr/Ba and V/V+Ni, combined with the biomarker compound in Pr/Ph and the gammacerane index showed the presence of a semi-deep – deep lake environment containing fresh–brackish water. In addition, the hydrocarbon conversion rate index and shale rock pyrolysis parameters revealed that Chang 7 has a high hydrocarbon generation ability and hydrocarbon expulsion efficiency.
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Tulan, Emilia, Michaela S. Radl, Reinhard F. Sachsenhofer, Gabor Tari, and Jakub Witkowski. "Hydrocarbon source rock potential of Miocene diatomaceous sequences in Szurdokpüspöki (Hungary) and Parisdorf/Limberg (Austria)." Austrian Journal of Earth Sciences 113, no. 1 (January 1, 2020): 24–42. http://dx.doi.org/10.17738/ajes.2020.0002.
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AbstractDiatomaceous sediments are often prolific hydrocarbon source rocks. In the Paratethys area, diatomaceous rocks are widespread in the Oligo-Miocene strata. Diatomites from three locations, Szurdokpüspöki (Hungary) and Limberg and Parisdorf (Austria), were selected for this study, together with core materials from rocks underlying diatomites in the Limberg area. Bulk geochemical parameters (total organic carbon [TOC], carbonate and sulphur contents and hydrogen index [HI]) were determined for a total of 44 samples in order to study their petroleum potential. Additionally, 24 samples were prepared to investigate diatom assemblages.The middle Miocene diatomite from Szurdokpüspöki (Pannonian Basin) formed in a restricted basin near a volcanic silica source. The diatom-rich succession is separated by a rhyolitic tuff into a lower non-marine and an upper marine layer. An approximately 12-m thick interval in the lower part has been investigated. It contains carbonate-rich diatomaceous rocks with a fair to good oil potential (average TOC: 1.28% wt.; HI: 178 to 723 mg HC/g TOC) in its lower part and carbonate-free sediments without oil potential in its upper part (average TOC: 0.14% wt.). The composition of the well-preserved diatom flora supports a near-shore brackish environment. The studied succession is thermally immature. If mature, the carbonate-rich part of the succession may generate about 0.25 tons of hydrocarbons per square meter. The diatomaceous Limberg Member of the lower Miocene Zellerndorf Formation reflects upwelling along the northern margin of the Alpine-Carpathian Foreland. TOC contents are very low (average TOC: 0.13% wt.) and demonstrate that the Limberg Member is a very poor source rock. The same is true for the underlying and over-lying rocks of the Zellerndorf Formation (average TOC: 0.78% wt.). Diatom preservation was found to differ considerably between the study sites. The Szurdokpüspöki section is characterised by excellent diatom preservation, while the diatom valves from Parisdorf/Limberg are highly broken. One reason for this contrast could be the different depositional environments. Volcanic input is also likely to have contributed to the excellent diatom preservation in Szurdokpüspöki. In contrast, high-energy upwelling currents and wave action may have contributed to the poor diatom preservation in Parisdorf. The hydrocarbon potential of diatomaceous rocks of Oligocene (Chert Member; Western Carpathians) and Miocene ages (Groisenbach Member, Aflenz Basin; Kozakhurian sediments, Kaliakra canyon of the western Black Sea) has been studied previously. The comparison shows that diatomaceous rocks deposited in similar depositional settings may hold largely varying petroleum potential and that the petroleum potential is mainly controlled by local factors. For example, both the Kozakhurian sediments and the Limberg Member accumulated in upwelling environments but differ greatly in source rock potential. Moreover, the petroleum potential of the Szurdokpüspöki diatomite, the Chert Member and the Groisenbach Member differs greatly, although all units are deposited in silled basins.
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Gresov, A. I., and A. V. Yatsuk. "Geological Implications for Gas Saturation of Bottom Sediments in Sedimentary Basins in the Southeastern Sector of the East Siberian Sea." Russian Geology and Geophysics 62, no. 2 (February 1, 2021): 157–72. http://dx.doi.org/10.2113/rgg20194075.
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Abstract —We present research results for the geologic structure of the De Long, Aion, and Pegtymel sedimentary basins of the East Siberian Sea. The materials of geological surveys and drilling in their land area and island surroundings, the data obtained from geophysical surveys conducted by Dal’morneftegeofizika, MAGE, and Sevmorgeologiya, and the seismic and deep-drilling data on the U.S. sector of the Chukchi Sea are summarized and analyzed. Pre-Paleozoic strata and the sedimentary cover have been identified throughout the sections of the sedimentary basins, which suggests the existence of a geologic “cover–basement” boundary rather than an arbitrary called “acoustic basement” horizon. The data on the geologic structure and gas saturation of the upper parts of the sedimentary sections were obtained during the study and gas-geochemical testing of core samples and bottom sediments from coastal shallow wells and corers. Gas contained in the rocks and bottom sediments in the study area includes hydrocarbon gases (HCGs) (СН4, С2–С5, and their unsaturated homologues), СО2, Н2, Не, N2, Ar, and, seldom, CO and H2S. The data on gas saturation of bottom sediments and the geochemical parameters of their syngenetic and epigenetic gases are presented. Areas of abnormal saturation of sediments with CO2, СН4, other HCGs, H2, and He (>5, 0.05, 0.001, 0.005, and 0.005 cm3/kg, respectively) have been identified, and maps of the gas saturation patterns in bottom sediments have been compiled. It is established that both gas saturation and distribution are determined mainly by the geologic evolution, tectonics, magmatism, geocryologic conditions, lithologic composition, catagenesis, coal content, bituminosity of sedimentary rocks, and oil and gas potential of the study area.
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Tao, Jia, Jinchuan Zhang, Junlan Liu, Yang Liu, Wei Dang, Haicheng Yu, Zhe Cao, Sheng Wang, and Zhe Dong. "Molecular and Carbon Isotopic Variation during Canister Degassing of Terrestrial Shale: A Case Study from Xiahuayuan Formation in the Xuanhua Basin, North China." Minerals 11, no. 8 (August 5, 2021): 843. http://dx.doi.org/10.3390/min11080843.
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Molecular and carbon isotopic variation during degassing process have been observed in marine shale reservoirs, however, this behavior remains largely unexplored in terrestrial shale reservoirs. Here, we investigate the rock parameters of five terrestrial shale core samples from the Xiahuayuan Formation and the geochemical parameters of thirty natural gas samples collected during field canister degassing experiments. Based on these new data, the gas composition and carbon isotope variation during canister degassing are discussed and, further, the relationship between petrophysics and the carbon isotope variation is explored. The results show that methane content first increases and then decreases, the concentrations of carbon dioxide (CO2) and nitrogen gas (N2) peak in the early degassing stage, while heavier hydrocarbons gradually increase over time. Shale gas generated from humic source rocks contains more non-hydrocarbon and less heavy hydrocarbon components than that generated from sapropelic source rocks with similar maturity. Time-series sampling presents an upward increase in δ13C1 value during the degassing process with the largest variation up to 5.7‰, while the variation in δ13C3 and δ13C2 is insignificant compared to δ13C1. Moreover, we find that there is only a small variation in δ13C1 in shale samples with high permeability and relatively undeveloped micropores, which is similar to the limited δ13C1 variation in conventional natural gas. For our studied samples, the degree of carbon isotope variation is positively correlated with the TOC content, micropore volume, and micropore surface, suggesting that these three factors may play a significant role in carbon isotope shifts during shale gas degassing. We further propose that the strong 13C1 and C2+depletion of shale gas observed during the early degassing stage may have resulted from the desorption and diffusion effect, which may lead to deviation in the identification of natural gas origin. It is therefore shale gas of the late degassing stage that would be more suitable for study to reduce analytic deviations. In most samples investigated, significant isotopic variation occurred during the degassing stage at room temperature, indicating that the adsorbed gas had already been desorbed at this stage Our results therefore suggest that more parameters may need to be considered when evaluating the lost gas of shales.
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Dash, Sabyasachi, and Zoya Heidari. "Enhanced Assessment of Fluid Saturation in the Wolfcamp Formation of the Permian Basin." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 62, no. 6 (December 1, 2021): 737–51. http://dx.doi.org/10.30632/pjv62n6-2020a10.
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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. They also do not reliably assimilate the spatial distribution of the clay network and pore structure. Moreover, they do not incorporate other conductive minerals and organic matter, impacting the resistivity measurements and leading to uncertainty in water saturation assessment. We recently introduced a resistivity-based model that quantitatively assimilates the type and spatial distribution of all rock constituents to improve reserves evaluation in organic-rich mudrocks using electrical resistivity measurements. This paper aims to expand the application of this model for well-log-based assessment of water/hydrocarbon saturation and to verify the reliability of the introduced method 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 nonconductive (grains, hydrocarbon) components in estimating effective resistivity. The inputs to the model are volumetric concentrations of minerals, 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 developed an inversion algorithm with two objectives: (a) to estimate the geometric model parameters as inputs to the new resistivity model and (b) to estimate the water saturation. The geometric model parameters are determined for each rock type or formation by minimizing the difference between the measured resistivity and the resistivity estimated from pore combination modeling. We applied the new method to two wells drilled in the Wolfcamp Formation of the Permian Basin. The formation-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 24.1% and 32.4% compared to Archie’s and Waxman-Smits models, respectively, in the Wolfcamp Formation. The most considerable improvement was observed in the Middle and the Lower Wolfcamp Formations, where the average clay concentration was relatively higher than the other zones. There was an additional 70,000 bbl/acre of hydrocarbon reserve using the proposed method compared to when water saturation was quantified using Archie’s model in the Permian Basin, which is a 33% relative improvement. It should be highlighted that the new method did not require any calibration effort using core water saturation measurements, which is a unique contribution of this rock-physics-based workflow.
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Huang, Handong, Sanyi Yuan, Yintao Zhang, Jing Zeng, and Wentao Mu. "Use of nonlinear chaos inversion in predicting deep thin lithologic hydrocarbon reservoirs: A case study from the Tazhong oil field of the Tarim Basin, China." GEOPHYSICS 81, no. 6 (November 2016): B221—B234. http://dx.doi.org/10.1190/geo2015-0705.1.
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With the gradual disappearance of traditional structural reservoirs, widely distributed deep thin lithologic reservoirs developed in continental and transitional sedimentary environments may offer significant petroleum reserves. Reservoir characterization through conventional impedance inversion methods without appropriate selection of regularization parameters and other empirical constraints cannot easily detect and assess these reserves, however, due to their size, variation, and features that conceal them. We have evaluated a nonlinear chaos inversion method that uses well data and seismic facies to characterize the oil and gas reservoirs of the Tazhong oil field in the Tarim Basin, China. The inverted results exhibited high agreement with the well data in highlighting the interfaces and lithologic bodies. This integrated method also provided enhanced resolution of depositional contacts and variable lithologic bodies. Specifically, the approach was able to describe a highly variable, approximately 5 m thick Carboniferous formation at depths greater than 3400 m. Borehole and core data provided a complementary hydrocarbon accumulation model. We used background information on hydrocarbon-bearing units within the main structure (an anticline) to detect and access (drill) ultra-thin lithologic reservoirs located in deeper areas of the structural high. Two wells drilled according to predictions derived from this new approach have each reached production rates of more than 30 tons of oil per day. Thus, we have determined the effectiveness of combining chaos inversion methods with empirical constraints in exploration of deep thin hydrocarbon reservoirs.
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Oyno, Lars, B. G. Tjetland, K. H. Esbensen, Rune Solberg, Aase Scheie, and Tore Larsen. "Prediction of Petrophysical Parameters Based on Digital Video Core Images." SPE Reservoir Evaluation & Engineering 1, no. 01 (February 1, 1998): 82–87. http://dx.doi.org/10.2118/36853-pa.
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Summary Core-slab photography is a common way to document geological information from cores. Past practice has been to photograph core slabs with ordinary cameras that produce paper photographs. The presented method retrieves petrophysical properties from high-resolution digital video core images. The procedures described in this work are based on video images (standard RIO/B camera) of cores taken with a digital recording system. The system is able to record in both visible and UV light at different illumination angles, store images, compress/decompress images, and display one or several images as a continuous long core. The seamless core image is marked with depth scale and can be scrolled, scaled, and zoomed. Facilities for correlation with other related data, such as wireline logs, discrete core data, and microscopy images, are also included in the system. We used homogenous dry core plugs from three North Sea oil fields in this work. We recorded images of plug surface, together with conventional core-analysis data (i.e., porosity, gas permeability, average grain size, and mineralogy). The new method is based on processed digital images: light/shadow patterns are obtained by use of asymmetric, low-angle illumination in the green channel. Texture spectra of the rock material are obtained by dedicated image-analytical processing of these gray-scale images and by detecting textural features by use of a unique set of specially designed texture filters. We then calibrate these spectra with respect to measured petrophysical parameters by use of multivariate calibration [partial least squares (PLS)-regression]. Multivariate calibration is based on a set of representative training images, selected to span representative ranges of the intensive petrophysical parameters being modeled. On the basis of this calibration model, similar gray-level video images from new, unknown core sections (with geologically similar facies) are used to estimate properties of the core material by PLS-prediction. In this study it has been possible to model porosity, gas permeability, and average grain size (ORZ) of different formations with a relatively high accuracy and precision. PLS-modeling/-prediction is a strict empirical calibration procedure. The present method is critically dependent upon a thorough, geologically well-documented training data set. Results show that the method is capable of predicting a continuous log of these three petrophysical parameters based on core images calibrated against a set of routine laboratory core-analysis data taken at discrete intervals for a particular formation. The advantages of the new method are rapid and cost-efficient methods for prediction of petrophysical parameters, particularly from slim cores, and improved integration of geological records with wireline data. The method is proposed to be included in future routine laboratory core analysis studies because of its low cost and ability to predict values continuously along the core. Introduction In many cases where core material is available from a potential hydrocarbon reservoir, it is possible to perform conventional laboratory core analysis on selected zones or at regular intervals. These measurements are commonly used as input in numerical simulations predicting recovery from the field. The results are also commonly used for net pay calculations to provide a reserves estimate.1–4 Usually, conventional core plugs are taken at regular intervals (every 30 cm or every meter) in the reservoir zone. Core-analysis plugs are often neglected below the oil/water contact (OWC), sometimes also in other parts of the reservoir for various reasons. Core photography has been used for decades to document the geology in the reservoir for later study. The photographs are usually printed on paper with a few core lengths in each photograph. Obtaining a complete picture of the reservoir geology and petrophysics from the core photographs involves extensive leafing through numerous pages of core photographs. Also, paper photographs do not offer the possibility to perform image analysis. Advances in digital storage and image analysis, together with decreasing costs of computers, have now allowed the use of digital storage of core information.5–8 The work described in this article makes exclusive use of digitally recorded imagery. Core images are taken continuously along the slabbed core. Software automatically combines the core images into a seamless, continuous core image of the complete length of the core's interval. This opens the door to easy access to image analysis. In contrast with the routine core-analysis measurements, the present digital video images provide continuous information regarding the texture of the core material. If these images also could be used to extract petrophysical information, they could offer parameter values continuously along the entire cored material. Because reservoir material differs widely from field to field and also between wells, we expected some initial experimentation with optimal recording parameters as well as the geological calibration base to be necessary to tune a new type of image correlation model. Consider an image of core material, say sandstone, where each grain can be seen at an appropriate resolution; it is not difficult to accept that image analysis should be able to extract grain-size (and grain-size distribution) information pertaining to the material in the field of view. Grains can be seen down almost throughout the fine range of the sandstone grain size. Moreover, when applying different data analytical techniques to postprocess, earlier-derived texture spectra, it became clear that even other petrophysical parameters like porosity and permeability could indeed also be predicted. Multivariate calibration,18,19 to be explained further later, is carried out from a number of calibration samples where the desired petrophysical parameters are known (from traditional methods). The camera field of view was maintained constant, and an analysis area large enough to be representative for all types of material in the present study was determined by initial sensitivity analysis. The advantage of the presented method is that petrophysical parameters now can be predicted directly from identical video imagery on samples which then, of course, need not be measured in the laboratory. This approach can even be augmented so as also to produce results from layered zones, where routine core-analysis results are difficult to obtain. It can also provide results where routine core-analysis results are doubtful, for example, in unconsolidated cores. Last, it provides continuous petrophysical estimates from a core at a detail and at significantly lowered cost, which is both impractical and uneconomical to achieve with conventional core analysis.
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Liu, Liang, Heping Pan, Chengxiang Deng, and Guoshu Huang. "A Method for Improving Permeability Accuracy of Tight Sandstone Gas Reservoirs Based on Core Data and NMR Logs." Energies 12, no. 15 (July 25, 2019): 2859. http://dx.doi.org/10.3390/en12152859.
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Accurate calculation of the permeability of tight sandstone gas reservoirs has been a challenge, due to the enhanced effect of pore structure. Reservoir permeability with the same porosity and different pore structure often varies greatly. The permeability estimated by the traditional core sample regression analysis method has low accuracy, and the nuclear magnetic resonance (NMR) logging method is affected by the hydrocarbon of the reservoir. In this paper, the defined parameter can effectively quantify the difference of pore structure. Based on regression analysis of core measurement data, the model with optimal factor parameters of permeability calculation is established. This method combines the advantages of empirical models and pore structure models in calculating permeability. The results show that the method can effectively improve the accuracy of permeability. It has been successfully applied to the tight sandstone gas reservoir of He3 member in Hangjinqi area, Ordos Basin, China. Compared with other permeability theoretical models, it provides a more accurate and practical method for calculating permeability.
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Atouabat, Achraf, Sveva Corrado, Andrea Schito, Faouziya Haissen, Oriol Gimeno-Vives, Geoffroy Mohn, and Dominique Frizon de Lamotte. "Validating Structural Styles in the Flysch Basin Northern Rif (Morocco) by Means of Thermal Modeling." Geosciences 10, no. 9 (August 19, 2020): 325. http://dx.doi.org/10.3390/geosciences10090325.
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Vitrinite reflectance and a micro-Raman spectroscopy parameters data set have been acquired on dispersed organic matter of the Maghrebian flysch basin and the Tangiers unit across a NE-SW section in the north-western Rif belt (North Morocco). Thermal maturity shows increasing values from the hinterland to the external unit (from NE to SW). Paleo-thermal indicators show that the internal flysch basin (i.e., the Mauretanian unit) is less mature than the external one, (i.e., the Massylian unit), with Ro% and Ro eq. Raman values ranging from 0.64% to 1.02% (from early mature to late mature stages of hydrocarbon generation). 1D thermal modeling estimates the overburden now totally eroded ranging from 3.1 km to 6.0 km, and has been used as constraint to reconstruct the complete thrust wedge geometry in Miocene times. The reconstructed geometry accounts for high shortening (about 63%) due to the development of an antiformal stack in the frontal part of the wedge made up by the flysch succession. This stacking is interpreted as a consequence of the western translation of the Alboran Domain in the core of the Betic-Rif orogenic system.
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Delfos, Ernie, and Malcolm Boardman. "WANDOO—A NEW TREND." APPEA Journal 34, no. 1 (1994): 586. http://dx.doi.org/10.1071/aj93045.
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In June 1991 a flow of 4 560 barrels of 19° API oil per day, from a depth of 600 m, heralded the discovery of a new hydrocarbon trend along the eastern margin of the Dampier Sub-basin on the North West Shelf of Australia. Wandoo–1 recovered oil and gas from lower Cretaceous sands associated with the M.australis dinoflagellate zone (Barremian), and gas from lower Jurassic Aalenian sands.The main reservoir at Wandoo is the M. australis Sandstone Member of the Muderong Shale. This is interpreted to be a shelfal shoal sand deposited in a minor regression phase during the regional transgression of the Muderong Shale. This reservoir is split into two main lithotypes, a glauconitic subarkose to subarenite, and an overlying greensand. Oil and gas have been recovered from both units, which are considered contiguous for reservoir definition. General reservoir parameters are exceptional. Since the initial discovery a 3D seismic survey has been acquired and appraisal drilling has proven approximately 250 MMSTBOIP.The unusual features of the field necessitated innovative exploration techniques and the need for a strong appraisal program. These techniques included a six streamer, high resolution, three dimensional seismic survey and its associated processing; development of methods to recover and preserve core in extremely unconsolidated sediments; use of non destructive core analysis methods such as nuclear magnetic resonance; and petrophysical analysis that incorporates the resistivity suppression problems of glauconite. Without core a very pessimistic view would have been taken of the M. australis Sandstone reservoir.The Wandoo discovery is on an exciting new trend previously overlooked due to the shallowness of reservoirs, lack of locally recognised source rocks and the dominance of other oil and gas trends in the Dampier Sub-basin and Barrow Sub-basin to the south.
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Suranto, Ahmad Muraji, Aris Buntoro, Carolus Prasetyadi, and Ricky Adi Wibowo. "Feasibility Study on the Application of Dynamic Elastic Rock Properties from Well Log for Shale Hydrocarbon Development of Brownshale Formation in the Bengkalis Trough, Central Sumatra Basin, Indonesia." Journal of Geoscience, Engineering, Environment, and Technology 6, no. 2 (June 8, 2021): 81–85. http://dx.doi.org/10.25299/jgeet.2021.6.2.5944.
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In modeling the hydraulic fracking program for unconventional reservoir shales, information about elasticity rock properties is needed, namely Young's Modulus and Poisson's ratio as the basis for determining the formation depth interval with high brittleness. The elastic rock properties (Young's Modulus and Poisson's ratio) are a geomechanical parameters used to identify rock brittleness using core data (static data) and well log data (dynamic data). A common problem is that the core data is not available as the most reliable data, so well log data is used. The principle of measuring elastic rock properties in the rock mechanics lab is very different from measurements with well logs, where measurements in the lab are in high stresses / strains, low strain rates, and usually drained, while measurements in well logging use the principle of measured downhole by high frequency sonic. vibrations in conditions of very low stresses / strains, High strain rate, and Always undrained. For this reason, it is necessary to convert dynamic to static elastic rock properties (Poisson's ratio and Young's modulus) using empirical equations. The conversion of elastic rock properties (well logs) from dynamic to static using the empirical calculation method shows a significant shift in the value of Young's Modulus and Poisson's ratio, namely a shift from the ductile zone dominance to the dominant brittle zone. The conversion results were validated with the rock mechanical test results from the analog outcrop cores (static) showing that the results were sufficiently correlated based on the distribution range.
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Talebkeikhah, Mohsen, Zahra Sadeghtabaghi, and Mehdi Shabani. "A Comparison of Machine Learning Approaches for Prediction of Permeability using Well Log Data in the Hydrocarbon Reservoirs." Journal of Human, Earth, and Future 2, no. 2 (June 1, 2021): 82–99. http://dx.doi.org/10.28991/hef-2021-02-02-01.
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Permeability is a vital parameter in reservoir engineering that affects production directly. Since this parameter's significance is obvious, finding a way for accurate determination of permeability is essential as well. In this paper, the permeability of two notable carbonate reservoirs (Ilam and Sarvak) in the southwest of Iran was predicted by several different methods, and the level of accuracy in all models was compared. For this purpose, Multi-Layer Perceptron Neural Network (MLP), Radial Basis Function Neural Network (RBF), Support Vector Regression (SVR), decision tree (DT), and random forest (RF) methods were chosen. The full set of real well-logging data was investigated by random forest, and five of them were selected as the potent variables. Depth, Computed gamma-ray log (CGR), Spectral gamma-ray log (SGR), Neutron porosity log (NPHI), and density log (RHOB) were considered efficacious variables and used as input data, while permeability was considered output. It should be noted that permeability values are derived from core analysis. Statistical parameters like the coefficient of determination ( ), root mean square error (RMSE) and standard deviation (SD) were determined for the train, test, and total sets. Based on statistical and graphical results, the SVM and DT models perform more accurately than others. RMSE, SD and R2values of SVM and DT models are 0.38, 1.63, 0.97 and 0.44, 2.89, and 0.96 respectively. The results of the best-proposed models of this paper were then compared with the outcome of the empirical equation for permeability prediction. The comparison indicates that artificial intelligence methods perform more accurately than traditional methods for permeability estimation, such as proposed equations. Doi: 10.28991/HEF-2021-02-02-01 Full Text: PDF
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Luo, Long, Dongping Tan, Xiaojun Zha, Xianfeng Tan, Jing Bai, Cong Zhang, Jia Wang, Lei Zhang, and Xuanbo Gao. "Enrichment Factors and Resource Potential Evaluation of Qingshankou Formation Lacustrine Shale Oil in the Southern Songliao Basin, NE China." Geofluids 2021 (January 27, 2021): 1–20. http://dx.doi.org/10.1155/2021/6645467.
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China shale oil, which is preserved in lacustrine shale with strong heterogeneity and relatively low maturity, has been a research hotspot of unconventional resources. However, controlling factors of shale oil enrichment and resource potential evaluation restricted efficient exploration and development of lacustrine shale oil. On the basis of well logging data, TOC content, Rock-Eval pyrolysis values, thermal maturity, 100 oil saturation data, and pressure coefficient, the core observation, X-ray diffraction analysis, physical property analysis, scanning electron microscopy, CT scan, well logging interpretation, and volumetric genesis method depending on three-dimensional geological modeling were used to determine enrichment factors and evaluate the resource potential of Qingshankou Formation shale oil in the Southern Songliao Basin. Shale oil was mainly enriched in the semideep and deep lake shale of K2qn1, with the high capacity of hydrocarbon generation and favorable petrological and mineralogical characteristics, pore space characteristics, and physical properties in the low structural part of the Southern Songliao Basin. The three-dimensional geological resource model of Qingshankou Formation lacustrine shale oil was determined by the key parameters (Ro, TOC, and S 1 ) of shale oil in the favorable zone of the Southern Songliao Basin, northeast China. The geological resource of shale oil, which was calculated by two grid computing methods ( F 1 and F 2 ), was, respectively, 1.713 × 10 12 kg and 1.654 × 10 12 kg . The great shale oil resource indicates a promising future in the exploration and development of Qingshankou Formation shale oil of the Southern Songliao Basin.
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Liu, Yuyang, Xiaowei Zhang, Junfeng Shi, Wei Guo, Lixia Kang, Rongze Yu, Yuping Sun, Zhelin Wang, and Mao Pan. "A reservoir quality evaluation approach for tight sandstone reservoirs based on the gray correlation algorithm: A case study of the Chang 6 layer in the W area of the as oilfield, Ordos Basin." Energy Exploration & Exploitation 39, no. 4 (March 22, 2021): 1027–56. http://dx.doi.org/10.1177/0144598721998510.
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As an important type of unconventional hydrocarbon, tight sandstone oil has great present and future resource potential. Reservoir quality evaluation is the basis of tight sandstone oil development. A comprehensive evaluation approach based on the gray correlation algorithm is established to effectively assess tight sandstone reservoir quality. Seven tight sandstone samples from the Chang 6 reservoir in the W area of the AS oilfield in the Ordos Basin are employed. First, the petrological and physical characteristics of the study area reservoir are briefly discussed through thin section observations, electron microscopy analysis, core physical property tests, and whole-rock and clay mineral content experiments. Second, the pore type, throat type and pore and throat combination characteristics are described from casting thin sections and scanning electron microscopy. Third, high-pressure mercury injection and nitrogen adsorption experiments are optimized to evaluate the characteristic parameters of pore throat distribution, micro- and nanopore throat frequency, permeability contribution and volume continuous distribution characteristics to quantitatively characterize the reservoir micro- and nanopores and throats. Then, the effective pore throat frequency specific gravity parameter of movable oil and the irreducible oil pore throat volume specific gravity parameter are introduced and combined with the reservoir physical properties, multipoint Brunauer-Emmett-Teller (BET) specific surface area, displacement pressure, maximum mercury saturation and mercury withdrawal efficiency parameters as the basic parameters for evaluation of tight sandstone reservoir quality. Finally, the weight coefficient of each parameter is calculated by the gray correlation method, and a reservoir comprehensive evaluation indicator (RCEI) is designed. The results show that the study area is dominated by types II and III tight sandstone reservoirs. In addition, the research method in this paper can be further extended to the evaluation of shale gas and other unconventional reservoirs after appropriate modification.
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Ali, Ahmed M., Ahmed E. Radwan, Esam A. Abd El-Gawad, and Abdel-Sattar A. Abdel-Latief. "3D Integrated Structural, Facies and Petrophysical Static Modeling Approach for Complex Sandstone Reservoirs: A Case Study from the Coniacian–Santonian Matulla Formation, July Oilfield, Gulf of Suez, Egypt." Natural Resources Research 31, no. 1 (December 2, 2021): 385–413. http://dx.doi.org/10.1007/s11053-021-09980-9.
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AbstractThe Coniacian–Santonian Matulla Formation is one of the important reservoirs in the July oilfield, Gulf of Suez Basin. However, this formation is characterized by uncertainty due to the complexity of reservoir architecture, various lithologies, lateral facies variations and heterogeneous reservoir quality. These reservoir challenges, in turn, affect the effectiveness of further exploitation of this reservoir along the Gulf of Suez Basin. In this work, we conduct an integrated study using multidisciplinary datasets and techniques to determine the precise structural, petrophysical, and facies characteristics of the Matulla Formation and predict their complex geometry in 3D space. To complete this study, 30 2D seismic sections, five digital well logs, and core samples of 75 ft (ft = 0.3048 m) length were used to build 3D models for the Matulla reservoir. The 3D structural model shows strong lateral variation in thickness of the Matulla Formation with NW–SE, NE–SW and N–S fault directions. According to the 3D facies model, shale beds dominate the Matulla Formation, followed by sandstone, carbonate, and siltstone beds. The petrophysical model demonstrates the Matulla reservoir's ability to store and produce oil; its upper and lower zones have good quality reservoir, whereas its middle zone is a poor quality reservoir. The most promising areas for hydrocarbon accumulation and production via the Matulla reservoir are located in the central, southeast, and southwest sectors of the oilfield. In this approach, we combined multiple datasets and used the most likely parameters calibrated by core measurements to improve the reservoir modeling of the complex Matulla reservoir. In addition, we reduced many of the common uncertainties associated with the static modeling process, which can be applied elsewhere to gain better understanding of a complex reservoir.
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Vadapalli, U., R. P. Srivastava, N. Vedanti, and V. P. Dimri. "Estimation of permeability of a sandstone reservoir by a fractal and Monte Carlo simulation approach: a case study." Nonlinear Processes in Geophysics 21, no. 1 (January 3, 2014): 9–18. http://dx.doi.org/10.5194/npg-21-9-2014.
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Abstract. Permeability of a hydrocarbon reservoir is usually estimated from core samples in the laboratory or from well test data provided by the industry. However, such data is very sparse and as such it takes longer to generate that. Thus, estimation of permeability directly from available porosity logs could be an alternative and far easier approach. In this paper, a method of permeability estimation is proposed for a sandstone reservoir, which considers fractal behavior of pore size distribution and tortuosity of capillary pathways to perform Monte Carlo simulations. In this method, we consider a reservoir to be a mono-dispersed medium to avoid effects of micro-porosity. The method is applied to porosity logs obtained from Ankleshwar oil field, situated in the Cambay basin, India, to calculate permeability distribution in a well. Computed permeability values are in good agreement with the observed permeability obtained from well test data. We also studied variation of permeability with different parameters such as tortuosity fractal dimension (Dt), grain size (r) and minimum particle size (d0), and found that permeability is highly dependent upon the grain size. This method will be extremely useful for permeability estimation, if the average grain size of the reservoir rock is known.
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Chen, Zhong Hong. "Biomarker Geochemistry and Hydrocarbon Generation Potential of the Evaporites in Dongying Lacustrine Basin." Advanced Materials Research 616-618 (December 2012): 1042–47. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.1042.
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To investigate hydrocarbon potential of the evaporites, some deep wells such as Haoke-1 well and Fengshen-2 well were intensively cored, tested by TOC, Rock-Eval, and chromatography and mass spectrometry and evaluated using geochemistry of biomarker and hydrocarbon generation. High content of gammacerane and low Pr/Ph was exhibited in the evaporite system compared to the non-evaporite system. Different response of biomarkers parameters for the different sedimentary systems was exhibited, such as C19/(C19+C23) terpanes, C29/(C27+C28+C29) steranes, C24/C23 and C22/C21 tricyclic terpane. The evaporites and mud stones have the capacity to generate and expel hydrocarbons. The tested samples were mostly typeⅠand typeⅡ1 of organic matter, and their original generating capacity can reach 40 mg/g rock and 20 mg/g rock respectively. The efficiency of hydrocarbon expulsion reached 60%, but the distribution of organic matter and its generative potential was highly variable. In general, the mudstones show greater generative potential than the evaporites. High maturity severely reduced the capacity of their rocks to generate and expel petroleum.
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Xiao, Juanjuan, Yufeng Xiao, Xinmin Ge, and Tianqi Zhou. "A Technique to Determine the Breakthrough Pressure of Shale Gas Reservoir by Low-Field Nuclear Magnetic Resonance." Energies 15, no. 19 (October 1, 2022): 7223. http://dx.doi.org/10.3390/en15197223.
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The porous and low-permeability characteristics of a shale gas reservoir determine its high gas storage efficiency, which is manifested in the extremely high breakthrough pressure of shale. Therefore, the accurate calculation of breakthrough pressure is of great significance to the study of shale gas preservation conditions. Based on a systematic analysis of a low-field NMR experiment on marine shales of the Longmaxi Formation in the Sichuan Basin, a shale gas breakthrough pressure determination technique different from conventional methods is proposed. The conventional methods have low calculation accuracy and are a tedious and time-consuming process, while low-field NMR technique is less time-consuming and of high accuracy. Firstly, the NMR T2 spectrum of shale core sample in different states is measured through low-field NMR experiment. The NMR T2 spectra of sample in water-saturated state and dry state are combined to model the mathematical relationship between shale gas breakthrough pressure and NMR T2 spectrum. It is found that the gas breakthrough pressure is power-exponentially related to the geometric mean of NMR T2 spectrum and positively related to the proportion of micropores. Accordingly, the shale gas breakthrough pressure is quickly and accurately calculated using continuous NMR logging data and then the sealing capacity of the shale caprocks is evaluated, providing basic parameters for analyzing unconventional hydrocarbon accumulation, preservation and migration. This technique has been successfully applied with actual data to evaluate the sealing capacity of shale caprock in a shale gas well in the Sichuan Basin. It can provide a good basis for the evaluation and characterization of shale oil and gas reservoirs.
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Anakwuba, Emmanuel Kenechukwu, Clement Udenna Onyekwelu, and Augustine Ifeanyi Chinwuko. "Integrated workflow approach to static modeling of Igloo R3 reservoir, onshore Niger Delta, Nigeria." Interpretation 3, no. 3 (August 1, 2015): SZ1—SZ14. http://dx.doi.org/10.1190/int-2014-0178.1.
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We constructed a 3D static model of the R3 reservoir at the Igloo Field, Onshore Niger Delta, by integrating the 3D seismic volume, geophysical well logs, and core petrophysical data. In this model, we used a combined petrophysical-based reservoir zonation and geostatistical inversion of seismic attributes to reduce vertical upscaling problems and improve the estimation of reservoir properties between wells. The reservoir structural framework was interpreted to consist of three major synthetic faults; two of them formed northern and southern boundaries of the field, whereas the other one separated the field into two hydrocarbon compartments. These compartments were pillar gridded into 39,396 cells using a [Formula: see text] dimension over an area of [Formula: see text]. Analysis of the field petrophysical distribution showed an average of 21% porosity, 34% volume of shale, and 680-mD permeability. Eleven flow units delineated from a stratigraphic modified Lorenz plot were used to define the reservoir’s stratigraphic framework. The calibration of acoustic impedance using sonic- and density-log porosity showed a 0.88 correlation coefficient; this formed the basis for the geostatistic seismic inversion process. The acoustic impedance was transformed into reservoir parameters using a sequential Gaussian simulation algorithm with collocated cokriging and variogram models. Ten equiprobable acoustic impedance models were generated and further converted into porosity models by using their bivariate relationship. We modeled the permeability with a single transform of core porosity with a correlation coefficient of 0.86. We compared an alternative model of porosity without seismic as a secondary control, and the result showed differences in their spatial distributions, which was a major control to fluid flow. However, there were similarities in their probability distribution functions and cumulative distribution functions.
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Ambrose, William A., and Eulise R. Ferrer. "Seismic stratigraphy and oil recovery potential of tide‐dominated depositional sequences in the Lower Misoa Formation (Lower Eocene), LL-652 Area, Lagunillas Field, Lake Maracaibo, Venezuela." GEOPHYSICS 62, no. 5 (September 1997): 1483–95. http://dx.doi.org/10.1190/1.1444252.
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Structurally complex, heterogeneous, estuarine‐delta and tide‐dominated shelf reservoirs in the Lower Misoa Formation (Lower Eocene C Members) in the LL-652 Area of Lagunillas Field in the Maracaibo Basin, Venezuela, had produced 135 million stock‐tank barrels (MMSTB) of oil as of 1993 but have a low recovery efficiency of 22 percent. In an 18-month joint study, the Bureau of Economic Geology (BEG) and Lagoven, S. A., demonstrated that these reservoirs will contain more than 900 MMSTB of unrecovered mobile oil at the end of primary recovery operations at the current 80‐acre well spacing. Two‐dimensional seismic, core, geophysical log, and production data were integrated to improve estimates of hydrocarbon reserves and to identify potential areas for secondary‐recovery projects in Lower Eocene reservoirs in the LL-652 Area. Maps of hydrocarbon pore volume (SoPhih) and remaining oil were derived from improved petrophysical characterization and production apportioning to specific reservoir horizons by permeability feet (kh). These maps indicate that most remaining oil lies in the poorly developed and structurally complicated north part of the field and where narrow [less than 2000 ft (<610 m) wide], high‐SoPhih belts are intersected by sealing and partly sealing reverse faults. The original‐oil‐in‐place resource base of the C Members in the LL-652 area increased by 867 MMSTB (60%) to 2318.2 MMSTB, mainly in the C-3-X and C-4-X Members, by identifying additional reservoir areas and improving quantification of porosity and other petrophysical parameters. Extended development on the current 80-acre [1968-ft (600-m)] well pattern will increase reserves from 127 to 302 MMSTB. However, 116 MMSTB, in addition to the 302 MMSTB, can be produced from 102 geologically based infill wells strategically targeted to tap areas of high remaining oil saturation in narrow sandstone bodies poorly contacted at the current well spacing. Horizontal and inclined wells in steeply dipping strata can capture additional volumes of poorly contacted mobile oil.
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Wang, Jingbin, Zhiliang He, Dongya Zhu, Zhiqian Gao, Xiaowei Huang, and Quanyou Liu. "Organic-Inorganic Geochemical Characteristics of the Upper Permian Pusige Formation in a High-Saline Lake Basin, Tarim Basin: Implications for Provenance, Paleoenvironments, and Organic Matter Enrichment." Geofluids 2021 (April 6, 2021): 1–26. http://dx.doi.org/10.1155/2021/6651747.
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The third member (M3) of the Upper Permian Pusige Formation is a prominent organic-rich lacustrine mudstone sequence within the Yecheng-Hetian Sag, Tarim Basin, hosting major petroleum resources. However, its depositional history and organic matter (OM) enrichment mechanism have received little attention. Therefore, various organic and inorganic geochemical analyses were performed on thirty-four core samples from the Well DW1, to elucidate their depositional paleoenvironments, provenance, and tectonic setting, as well as the controlling factors of OM enrichment. Results showed that the M3 mudstones are classified as poor- to fair-quality hydrocarbon source rocks with mature type II-III kerogen, considering their low organic geochemical parameters. Paleosalinity indexes (e.g., Beq, Sr/Ba, and B/Ga) indicated the typical high-saline lacustrine water body, in which redox state was the oxic-dysoxic as suggested by multiple indicators. Many paleoclimate and weathering proxies suggest a dominant semiarid condition and low weathering degree in the Yecheng-Hetian Sag, which led to that weathered felsic rocks from the West Kunlun Orogen to the southwest of basin were quickly transported into the lake basin. Detrital materials carrying nutrient elements finally promoted the development of relatively high paleoproductivity indicated by fairly high P/Ti and Ba/Al ratios. The negative relationship between P/Ti and total organic carbon (TOC) indicates that paleoproductivity was not the main controlling factor. The correlations among TOC and P/Ti and other multiple proxies suggest that the OM enrichment can be interpreted as both the “preservation model” and “dilution model.” Although the water body was relatively oxygen-riched, high sedimentation rate could largely shorten the exposure time of OM with oxygen, thus decreased the decomposition of OM. In particular, the high-saline, stratified lake water may also restrain the degradation of OM. Furthermore, detrital dilution exerted a potential effect on TOC abundances. On the basis of the above results, a developing model was established to decipher the formation mechanism of OM in these M3 mudstones.
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Ogoreltcev, Vadim Iu, Sergei A. Leontev, Valentin A. Korotenko, Sergei I. Grachev, Valerii F. Diagilev, and Oleg V. Fominykh. "LABORATORY STUDY OF INFLUENCE OF RHEOLOGICAL CHARACTERISTICS OF CROSS-LINKED POLYMER SYSTEMS ON PERMEABILITY AND OIL DISPLACEMENT COEFFICIENTS." Вестник Пермского национального исследовательского политехнического университета. Геология. Нефтегазовое и горное дело 20, no. 2 (June 2020): 162–74. http://dx.doi.org/10.15593/2224-9923/2020.2.6.
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In development of hard-to-recover hydrocarbon reserves, enhanced oil recovery methods are applied on a massive scale, chemical methods being the most common ones. Each formation stimulation technology is associated with certain application conditions which depend on the initial geological and physical formation parameters and current state of its development. Methodological approach is provided for determination of permeability coefficient and coefficient of oil displacement from rock during testing of compositions of technologies of physical and chemical enhanced oil recovery methods on the basis of laboratory studies of rheological properties of various brands of acrylamide polymer. The methods have been developed according to the requirements to core analysis. The study provides a list of equipment and basic characteristics of the filtration system, as well as the procedure for preparation of working fluids and laboratory formation to laboratory study. Laboratory study of gel systems’ rheological properties is performed on the basis of the technological process for preparation of components of viscoelastic compound recipe at the wellhead and its further injection into the formation. To this end, in order to determine the rheological properties of gel systems, a special-purpose rheometer was used, with a capability to dynamically register the changing viscosity data of the tested polymer systems prepared on the analogues of fresh, produced and Cenomanian waters in “well – formation” thermobaric conditions. Based on the laboratory studies, it has been shown that trial injections of cross-linked compositions on the basis of polyacrylamide (PAA) of brands FP-107 and Ро1у-Т-101, possessing the capability of multifold increase of final viscosity of the polymer composition (by 2–3 times and more) in conditions of increasing temperature in low salinity waters (produced, Cenomanian), enable higher technological effectiveness compared to brand FP-307 polyacrylamide presently used in the company’s oilfields.
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Lerche, I., and F. Rocha-Legoretta. "Risking Basin Analysis Results." Energy Exploration & Exploitation 21, no. 2 (April 2003): 81–164. http://dx.doi.org/10.1260/014459803322362459.
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The work presented here uses a basin analysis code, developed for Excel, to handle burial history, fluid flow, fracturing, overpressure development with time, erosion events, kerogen breakdown to oil and gas, hydrocarbon volumetrics for both oil and gas including source retention, migration loss, and area changes with time of source rocks for each formation. The code is remarkably fast, requiring about 0.2 seconds on a laptop to perform all the above calculations for ten formations as well as producing pictorial representations of all variables with space and time. The code seamlessly interfaces with the Monte Carlo risking program Crystal Ball so that a total uncertainty analysis can be done with as many uncertain inputs as required and as many outputs of interest as needed without increasing the computer time needed. A thousand Crystal Ball runs take only about 200 seconds, allowing one to investigate many possible scenarios extremely quickly. We show here with four basic examples how one goes about identifying which parameters in the input (ranging from uncertain data, uncertain thermal history, uncertain permeability, uncertain fracture coefficients for rocks, uncertain geochemistry kinetics, uncertain kerogen amounts and types per formation, through to uncertain volumetric factors) are causing the greatest contributions to uncertainty in any and all outputs. The relative importance, relative contributions and relative sensitivity are examined to show when it is necessary to know more about the underlying distributions of uncertain parameters, when it is necessary to know more about the dynamic range of a parameter to narrow its contribution to the total uncertainty, and which parameters are necessary to first focus on to narrow their uncertainty in order to improve the dynamical, thermal or hydrocarbon outputs. An interface of such a coupled pair of very fast Excel codes with an Excel economics package can also now easily be undertaken so that one ties scientific uncertainty and economic uncertainty together for hydrocarbon exploration and identifies the global parameters dominantly influencing the combined economic/basin analysis system.
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Varga, Andrea, Elemér Pál-Molnár, and Béla Raucsik. "Revealing the Mineralogical and Petrographic Signs of Fluid-Related Processes in the Kelebia Basement Area (Szeged Basin, S Hungary): A Case Study of Alpine Prograde Metamorphism in a Permo-Triassic Succession." Geofluids 2023 (January 25, 2023): 1–18. http://dx.doi.org/10.1155/2023/8600576.
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The Szeged Basin (S Hungary) occupies a relatively central position within the European Alpine–Carpathian–Dinaride orogenic belt. An ongoing controversy about the tectonic position of the study area indicates that its evolution is still not fully understood; however, several important hydrocarbon occurrences are known in the fractured basement reservoirs. The main aim of this contribution is to investigate the petrographic features and possible Alpine metamorphic conditions of volcanic/volcanoclastic and siliciclastic rocks from the Kelebia basement area. Due to the outcrop conditions and poor exposure, study samples are obtained from cores and core chips resulting from oil exploration. Based on an evaluation of petrographic (including also cathodoluminescence analysis) and microstructural features, joined with mineralogical and metamorphic data such as “illite crystallinity” and K-white mica crystallite size obtained by X-ray powder diffractometry (XRPD), a very low- to low-grade (ca. 300°C) Alpine metamorphic imprint of this portion of the basement can be proposed. Several deformation characteristics (deformation lamellae in quartz, deformation twins in dolomite, fragmented porphyroclasts, and strain shadows) were recognized in the studied samples, showing a weakly to moderately developed disjunctive foliation in the Permian rocks, as well as quartz veinlets, microcracks, and fluid inclusion planes in the Lower Triassic sandstones. Most likely, one of the Cretaceous orogenic events, namely, the “Turonian” phase (Early–Late Cretaceous nappe stacking), resulted in the prograde greenschist facies metamorphism in the study area, instead of the burial depth. We propose that the Permo-Triassic cover succession was also affected by shearing episodes accompanied by fluid migrations along the contact zone between the tectonic units. The scientific approach and dataset provided here are examples of how the application of XRPD parameters of phyllosilicates and micropetrographic observations can help to understand the evolution of an orogen and improve knowledge about the basement structure.
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Widarsono, Bambang. "POROSITY VERSUS DEPTH CHARACTERISTICS OF SOME RESERVOIR SANDSTONES IN WESTERN INDONESIA." Scientific Contributions Oil and Gas 37, no. 2 (February 15, 2022): 87–104. http://dx.doi.org/10.29017/scog.37.2.629.
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Porosity is a petrophysical property that always draws attention due to its central role in determiningstorage capacity of hydrocarbon reservoirs. Accuracy for predicting porosity in reservoir affects much ofmany petroleum production related activities. Accordingly, various attempts have been devoted to study andmodel rock porosity including its relation with depth. In this study porosity data from as many as 4654 coresamples (1773 full-diameter core plugs and 2881 sidewall core samples) is used. The core samples were takenfrom 549 wells in 222 fi elds/structures located in eight producing sedimentary basins in western Indonesia.Main results of the study are facts that existing porosity-depth models derived from data obtained from otherregions are not usable for Indonesian cases, and therefore porosity-depth models are established for theeight sedimentary basins. It is hoped that these models can contribute signifi cantly to the understanding ofrock porosity trends with depth in western Indonesia.
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Niu, Zicheng, Zheng Li, Xiuhong Wang, Huiping Liu, Juan Wang, Xuan Liu, and Ru Wang. "Application of NSO compounds in the research of hydrocarbon migration direction in the Wangjiagang area of the Dongying sagin the Bohai Bay Basin." E3S Web of Conferences 245 (2021): 03085. http://dx.doi.org/10.1051/e3sconf/202124503085.
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The determination of hydrocarbon migration direction is an important part in the study of petroleum accumulation in petroliferous basins, and plays an important role in guiding oil and gas exploration activity. Despite their relatively low content in petroleum, the polar nitrogen-, sulphur-and oxygen- containing compounds (collectively referred to as NSO compounds) have great potential in characterizing the hydrocarbon migration process. A series of crude oils along hydrocarbon migration pathway were selected and analysed using GC×GC/TOFMS and GC-MS in the Wangjiagang area of the Dongying sag. Total concentration of NSO compounds and other related parameters are determined to verify the role of different parameters in indicating hydrocarbon migration. Our research result shows that the total amount of NSO compounds, 1-/3-MC ratio, 1,8-/2,7-DMC ratio, 4-/1-MDBF ratio and 2,4-/1,4-DMDBT ratio changes grandully with the increase of migration distances. Thus, these parameters can be applied as effective migration direction indicators in study area. Some other parameters may not be suitable for the identification of hydrocarbon migration direction in the study area.
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Ahmadov, E. H. "The study of regularities of distribution of reservoir parameters." Azerbaijan Oil Industry, no. 12 (December 15, 2022): 4–9. http://dx.doi.org/10.37474/0365-8554/2022-12-4-9.
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The parameters of reservoir should be specified in order to calculate hydrocarbon reserves. In particular, the uncertainty of reservoir parameters occurs mostly in the new areas. Thus, for the geological substantiation of reservoir parameters in these areas an analogy method is used. However, in the geological substantiation of reservoir parameters with analogical approach, it is essential to use the data on the field development in adjacent territories not in numerical order, but considering the distribution regularity. Such an approach allows specifying the uncertainty degree of reservoir parameters in the calculation of hydrocarbon reserves of the fields. The distribution regularities of reservoir parameters have been studied by the horizons in the fields of South Caspian Basin that has a great significance for the update of hydrocarbon reserves of the fields, for the efficiency of field development, as well as for the specification of the ways of reducing geological risks. Therefore, for the calculation or update of hydrocarbon reserves of the fields in South Caspian Basin, the statistical limits of reservoir parameters (maximum, minimum, mode etc.) and distribution regularities (normal, lognormal) have been studied. This paper may be used not only in the South Caspian, but in other oil-gas basins of Azerbaijan as well.
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Spiteri, Elizabeth J., Ruben Juanes, Martin J. Blunt, and Franklin M. Orr. "A New Model of Trapping and Relative Permeability Hysteresis for All Wettability Characteristics." SPE Journal 13, no. 03 (September 1, 2008): 277–88. http://dx.doi.org/10.2118/96448-pa.
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Summary The complex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that, whenever the fluid saturations undergo a cyclic process, relative permeabilities display hysteresis effects. In this paper, we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability, which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties, most notably the wettability and the initial water saturation. The new model is able to capture two key features of the observed behavior:non-monotonicity of the initial-residual curves, which implies that waterflood relative permeabilities cross; andconvexity of the waterflood relative permeability curves for oil-wet media caused by layer flow of oil. Introduction Hysteresis refers to irreversibility or path dependence. In multiphase flow, it manifests itself through the dependence of relative permeabilities and capillary pressures on the saturation path and saturation history. From the point of view of pore-scale processes, hysteresis has at least two sources: contact angle hysteresis, and trapping of the nonwetting phase. The first step in characterizing relative permeability hysteresis is the ability to capture the amount of oil that is trapped during any displacement sequence. Indeed, a trapping model is the crux of any hysteresis model: it determines the endpoint saturation of the hydrocarbon relative permeability curve during waterflooding. Extensive experimental and theoretical work has focused on the mechanisms that control trapping during multiphase flow in porous media (Geffen et al. 1951; Lenormand et al. 1983; Chatzis et al. 1983). Of particular interest to us is the influence of wettability on the residual hydrocarbon saturation. Early experiments in uniformly wetted systems suggested that waterflood efficiency decreases with increasing oil-wet characteristics (Donaldson et al. 1969; Owens and Archer 1971). These experiments were performed on cores whose wettability was altered artificially, and the results need to be interpreted carefully for two reasons:reservoirs do not have uniform wettability, and the fraction of oil-wet pores is a function of the topology of the porous medium and initial water saturation (Kovscek et al. 1993); andthe coreflood experiments were not performed for a long enough time, and not enough pore volumes were injected to drain the remaining oil layers to achieve ultimate residual oil saturation. In other coreflood experiments, in which many pore volumes were injected, the observed trapped/residual saturation did not follow a monotonic trend as a function of wettability, and was actually lowest for intermediate-wet to oil-wet rocks (Kennedy et al. 1955; Moore and Slobod 1956; Amott 1959). Jadhunandan and Morrow (1995) performed a comprehensive experimental study of the effects of wettability on waterflood recovery, showing that maximum oil recovery was achieved at intermediate-wet conditions. An empirical trapping model typically relates the trapped (residual) hydrocarbon saturation to the maximum hydrocarbon saturation; that is, the hydrocarbon saturation at flow reversal. In the context of waterflooding, a trapping model defines the ultimate residual oil saturation as a function of the initial water saturation. The most widely used trapping model is that of Land (1968). It is a single-parameter model, and constitutes the basis for a number of relative permeability hysteresis models. Other trapping models are those of Jerauld (1997a) and Carlson (1981). These models are suitable for their specific applications but, as we show in this paper, they have limited applicability to intermediate-wet and oil-wet media. Land (1968) pioneered the definition of a "flowing saturation," and proposed to estimate the imbibition relative permeability at a given actual saturation as the drainage relative permeability evaluated at a modeled flowing saturation. Land's imbibition model (1968) gives accurate predictions for water-wet media (Land 1971), but fails to capture essential trends when the porous medium is weakly or strongly wetting to oil. The two-phase hysteresis models that are typically used in reservoir simulators are those by Carlson (1981) and Killough (1976). A three-phase hysteresis model that accounts for essential physics during cyclic flooding was proposed by Larsen and Skauge (1998). These models have been evaluated in terms of their ability to reproduce experimental data (Element et al. 2003; Spiteri and Juanes 2006), and their impact in reservoir simulation of water-alternating-gas injection (Spiteri and Juanes 2006; Kossack 2000). Other models are those by Lenhard and Parker (1987), Jerauld (1997a), and Blunt (2000). More recently, hysteresis models have been proposed specifically for porous media of mixed wettability (Lenhard and Oostrom 1998; Moulu et al. 1999; Egermann et al. 2000). All of the hysteresis models described require a bounding drainage curve and either a waterflood curve as input, or a calculated waterflood curve using Land's model. The task of experimentally determining the bounding waterflood curves from core samples is arduous, and the development of an empirical model that is applicable to non-water-wet media is desirable. In this paper, we introduce a relative permeability hysteresis model that does not require a bounding waterflood curve, and whose parameters may be correlated to rock properties such as wettability and pore structure. Because it is difficult to probe the full range of relative permeability hysteresis for different wettabilities experimentally, we use a numerical tool--pore-scale modeling--to predict the trends in residual saturation and relative permeability. As we discuss later, pore-scale modeling is currently able to predict recoveries and relative permeabilities for media of different wettability reliably (Dixit et al. 1999; Øren and Bakke 2003; Jackson et al. 2003; Valvatne and Blunt 2004; Al-Futaisi and Patzek 2003, 2004). We will use these predictions as a starting point to explore the behavior beyond the range probed experimentally. In summary, this paper presents a new model of trapping and waterflood relative permeability, which is able to capture the behavior predicted by pore-network simulations for the entire range of wettability conditions.
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Wang, Ziyi, Zhiqian Gao, Tailiang Fan, Hehang Zhang, Lixin Qi, and Lu Yun. "Hydrocarbon-bearing characteristics of the SB1 strike-slip fault zone in the north of the Shuntuo Low Uplift, Tarim Basin." Petroleum Geoscience 27, no. 1 (July 1, 2020): petgeo2019–144. http://dx.doi.org/10.1144/petgeo2019-144.
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The SB1 strike-slip fault zone, which developed in the north of the Shuntuo Low Uplift of the Tarim Basin, plays an essential role in reservoir formation and hydrocarbon accumulation in deep Ordovician carbonate rocks. In this research, through the analysis of high-quality 3D seismic volumes, outcrop, drilling and production data, the hydrocarbon-bearing characteristics of the SB1 fault are systematically studied. The SB1 fault developed sequentially in the Paleozoic and formed as a result of a three-fold evolution: Middle Caledonian (phase III), Late Caledonian–Early Hercynian and Middle–Late Hercynian. Multiple fault activities are beneficial to reservoir development and hydrocarbon filling. In the Middle–Lower Ordovician carbonate strata, linear shear structures without deformation segments, pull-apart structure segments and push-up structure segments alternately developed along the SB1 fault. Pull-apart structure segments are the most favourable areas for oil and gas accumulation. The tight fault core in the centre of the strike-slip fault zone is typically a low-permeability barrier, whilst the damage zones on both sides of the fault core are migration pathways and accumulation traps for hydrocarbons, leading to heterogeneity in the reservoirs controlled by the SB1 fault. This study provides a reference for hydrocarbon exploration and development of similar deep-marine carbonate reservoirs controlled by strike-slip faults in the Tarim Basin and similar ancient hydrocarbon-rich basins.
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Shuster, V. L. "Methodical approach to forecasting zones in oil and gas bearing basins favorable for the formation of non-anticlinal traps." Actual Problems of Oil and Gas, no. 29 (November 19, 2020): 64–71. http://dx.doi.org/10.29222/ipng.2078-5712.2020-29.art5.
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The article discusses the goals, objectives, methods and types of geological and geophysical studies, as well as the forecast criteria for non-anticlinal oil and gas traps at the regional stage of exploration. Proposals are made to improve and systematize existing methods for predicting non-anticlinal traps. Geological and geophysical data on hydrocarbon deposits and exploration areas of Western Siberia are utilized. Comprehensive analysis of seismic data, well logs and core data is carried out using modern research methods.
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Brink, Heinz-Jurgen. "Albert Einstein, World of Dices and Hydrocarbon System Analysis." International Journal of Sustainable Energy and Environmental Research 11, no. 2 (October 5, 2022): 86–103. http://dx.doi.org/10.18488/13.v11i2.3154.
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Albert Einstein, Caesar and others have used dices as a metaphor for risks and probabilities; indirectly reverting to the experience human kind may have with natural processes in its environment contemporarily with human evolution. It will be shown for example by concentrating on the exploration of hydrocarbons that the rules of a dice-game can be used to better understand the importance of the number of ruling parameters (dices), in this case geological parameters. Especially the Rotliegend Gas Play of the North German Basin belongs to the very complex hydrocarbon systems with more than 70 independent parameters. The Dutch Rotliegend Play for comparison can be characterized by only 10 parameters and is therefore of a simple type. Processes on earth like the formation of systems of hydrocarbon fields as well as environmental systems (e.g. river systems, lakes, islands, sedimentary basins) are subordinated to the dice of nature like in a Casino and are steered invisibly by a selection of rules of the game that one understands as natural laws. The complexity of a system as well as the variedness of its “members” that may be found in anthropogenic systems as well (different properties in thinking, self-reflection, feedback-capabilities, combative and ambitious behavior of individuals with the target to climb upwards in a ranking matrix) is decided by the number of the influencing parameters, represented by dices. Like in a dice-game the exploration of hydrocarbons is unsolvable connected to luck and bad-luck, coincidence and necessity, and to past and future.
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Hopkins, Roy M. "THE CENTRAL AUSTRALIAN BASINS." APPEA Journal 29, no. 1 (1989): 347. http://dx.doi.org/10.1071/aj88030.
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The Amadeus and Ngalia Basins are two of several intracratonic basins situated in the central region of the Australian Continent and underlain by Upper Proterozoic and Lower Palaeozoic sedimentary rocks.In the Amadeus Basin, the preserved sedimentary section has been deformed by several orogenic events through geological history, with salt tectonics playing an important role in the structural evolution. The Ordovician System is the primary exploration objective. The Cambrian and Proterozoic sequences, which also carry rock strata having source, reservoir and sealing properties, are secondary targets. However, these latter units are sparsely explored, and only limited information is available on their petroleum prospectiveness. Three of the four petroleum accumulations found to date are in Ordovician sandstones, with the fourth accumulation contained in Cambrian sandstones.The initial drilling phase in the Amadeus Basin in the early 1960s was concentrated on geologically defined surface antic :nes, with seismic surveying becoming the principal technique employed in subsequent exploration phases. The ongoing work has demonstrated a major untested structural play associated with a regional thrust fault system — in particular, combination dip and fault closures developed on the underthrust blocks. Stratigraphic prospects also are present in the Amadeus Basin, but none of these yet has been drilled.The Ngalia Basin is similar stratigraphically and structurally to the Amadeus Basin and is considered prospective for oil and gas. Much less work has been done in the Ngalia than in the Amadeus, with only one well drilled in the entire basin. The well yielded a gas snow from a Proterozoic formation, and other direct hydrocarbon indications have been recorded elsewhere in the basin. Rock units having source, reservoir and sealing parameters are present, as are structures capable of forming traps. Again, these are associated largely with a complex regional thrust fault system.
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Bailey, Adam, Rosalind King, Simon Holford, Joshua Sage, Martin Hand, and Guillaume Backe. "Defining structural permeability in Australian sedimentary basins." APPEA Journal 55, no. 1 (2015): 119. http://dx.doi.org/10.1071/aj14010.
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Declining conventional hydrocarbon reserves have triggered exploration towards unconventional energy, such as CSG, shale gas and enhanced geothermal systems. Unconventional play viability is often heavily dependent on the presence of secondary permeability in the form of interconnected natural fracture networks that commonly exert a prime control over permeability due to low primary permeabiliy of in situ rock units. Structural permeability in the Northern Perth, SA Otway, and Northern Carnarvon basins is characterised using an integrated geophysical and geological approach combining wellbore logs, seismic attribute analysis and detailed structural geology. Integration of these methods allows for the identification of faults and fractures across a range of scales (millimetre to kilometre), providing crucial permeability information. New stress orientation data is also interpreted, allowing for stress-based predictions of fracture reactivation. Otway Basin core shows open fractures are rarer than image logs indicate; this is due to the presence of fracture-filling siderite, an electrically conductive cement that may cause fractures to appear hydraulically conductive in image logs. Although the majority of fractures detected are favourably oriented for reactivation under in situ stresses, fracture fill primarily controls which fractures are open, demonstrating that lithological data is often essential for understanding potential structural permeability networks. The Carnarvon Basin is shown to host distinct variations in fracture orientation attributable to the in situ stress regime, regional tectonic development and local structure. A detailed understanding of the structural development, from regional-scale (hundreds of kilometres) down to local-scale (kilometres), is demonstrated to be of importance when attempting to understand structural permeability.
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Sun, Yuzhuang, J. P. Sun, H. J. Zhang, and L. F. Liu. "Recovery of Original Organic Parameters of the the Outcropping Source Rocks from South China." Energy Exploration & Exploitation 20, no. 5 (October 2002): 365–70. http://dx.doi.org/10.1260/014459802321146965.
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Two samples from outcrops and six core samples of the clay source rocks from the Shiwanshan and Baise Basins were analysed in order to study the variation of selected organic parameters. A comparison of the samples taken from the outcrops with core samples was then performed. The results indicate a significant alteration of the organic matter at and near the surface. A depletion of about 70% TOC and extract yields was seen. The depth influenced by oxidation was found to be about 50 m. The most significant depletion of the organic matter occurred within 16 m.
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Gladysheva, Y. I. "Main directions of searching for hydrocarbons in Nadym-Pursk oil and gas region." Oil and Gas Studies, no. 4 (September 9, 2021): 23–31. http://dx.doi.org/10.31660/0445-0108-2021-4-23-31.
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Nadym-Pursk oil and gas region has been one of the main areas for the production of hydrocarbon raw materials since the sixties of the last century. A significant part of hydrocarbon deposits is at the final stage of field development. An increase in gas and oil production is possible subject to the discovery of new fields. The search for new hydrocarbon deposits must be carried out taking into account an integrated research approach, primarily the interpretation of seismic exploration, the creation of geological models of sedimentary basins, the study of geodynamic processes and thermobaric parameters. Statistical analysis of geological parameters of oil and gas bearing complexes revealed that the most promising direction of search are active zones — blocks with the maximum sedimentary section and accumulation rate. In these zones abnormal reservoir pressures and high reservoir temperatures are recorded. The Cretaceous oil and gas megacomplex is one of the main prospecting targets. New discovery of hydrocarbon deposits are associated with both additional exploration of old fields and the search for new prospects on the shelf of the north. An important area of geological exploration is the productive layer of the Lower-Berezovskaya subformation, in which gas deposits were discovered in unconventional reservoirs.
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Pang, Xiongqi, Ian Lerche, Chen Fajin, and Chen Zhangming. "Hydrocarbon Expulsion Threshold: Significance and Applications to Oil and Gas Exploration." Energy Exploration & Exploitation 16, no. 6 (December 1998): 539–55. http://dx.doi.org/10.1177/014459879801600603.
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Hydrocarbon explusion threshold (HET) is the critical condition for hydrocarbon expulsion in separate phase from a source rock when the generated hydrocarbon amount has satisfied all needs for absorption by minerals, solution in water, and blocking of capillary pressure. Research results show that the HET varies mainly with three geological parameters: total organic carbon content (C%), kerogen type index (KTI) and thermal maturation degree (R0). Source rocks with low C% and KTI cross the HET at a high level of maturation degree (larger R0); source rocks with lower R0 and C% can also cross the HET if the kerogen has a larger KTI. Under general geological conditions, a source rock first crosses the methane expulsion threshold (HETgl), then the heavy hydrocarbon gas threshold (HETgn), and finally the liquid hydrocarbon expulsion threshold (HET0). In this paper the concept of HET, and its critical conditions, are applied to establish the scientific validity of the concept and grade the source rocks, to study the phases of hydrocarbons in migration and the mechanisms of hydrocarbon accumulation, and to divide the hydrocarbon expulsion into stages. Applications to different basins in China show that HET provides an accurate and efficient method to guide oil and gas prospecting.
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Rigueti, Ariely L., Patrick Führ Dal' Bó, Leonardo Borghi, and Marcelo Mendes. "Bioclastic accumulation in a lake rift basin: The Early Cretaceous coquinas of the Sergipe–Alagoas Basin, Brazil." Journal of Sedimentary Research 90, no. 2 (February 27, 2020): 228–49. http://dx.doi.org/10.2110/jsr.2020.11.
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ABSTRACT Coquinas constitute widespread deposits in lacustrine, estuarine, and shallow marine settings, where they are a valuable source of information on environmental conditions. Thick coquina successions were deposited in a series of lacustrine rift basins that formed along the Brazilian Continental Margin during the early stages of the opening of the South Atlantic Ocean, in the Early Cretaceous. In the Sergipe–Alagoas Basin, the coquina sequence, equivalent to the Morro do Chaves Formation, crops out in the Atol Quarry, and is considered a relevant analog for the economically important hydrocarbon reservoirs in the Pre-salt strata (Barremian to Aptian) of the Campos Basin (Pampo, Badejo, and Linguado oil fields), which occur only in the subsurface. The aim of this study is to generate a depositional and stratigraphic model through facies and stratigraphic analyses of a well core. These analyses allowed the geological characterization of the Morro do Chaves Formation and of its transition to the adjacent stratigraphic units, the Coqueiro Seco Formation above and the Penedo Formation below, contributing to the growing knowledge of sedimentation in rift basins and exploratory models in hydrocarbon-producing reservoirs. Facies analysis consists of sedimentological, taphonomic, and stratigraphic features of the rocks. Fourteen depositional facies were recognized, stacked into low-frequency and high-frequency, deepening-upward and shallowing-upward cycles driven by the interaction between climate and tectonism. A depositional model is presented, based on the correlation between well-core and outcrop data described in previous studies, providing insights into the spatial distribution of facies. The detailed analysis of facies and stacking patterns sheds light on depositional processes, paleoenvironmental conditions, and the evolution of the system through time, so we may better understand analogous deposits in the geological record.
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Ryazanova, T. A., V. V. Markov, and I. G. Pavlutkin. "Comprehensive characteristics of organic matter in the Jurassic deposits of the western part of the Uvat region." Interexpo GEO-Siberia 2, no. 1 (May 18, 2022): 48–55. http://dx.doi.org/10.33764/2618-981x-2022-2-1-48-55.
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Original studies of a collection of Jurassic core samples from three wells (690 m) of the areas in the Uvat region of the West Siberian oil and gas basin were carried out. The areas are located in the submeridional direction: Radonezhskaya (north), Malouimskaya (northwest) and West Turtasskaya (southwest). The aim of the work is to conduct a comparative analysis of the parameters characterizing dispersed organic matter (DOM) in core samples from Jurassic rock formations in the studied wells. The accumulation conditions and the type of DOM, its catagenetic transformation were “restored”. The quality of DOM and its ability to generate hydrocarbons have been evaluated. The main research method is pyrolytic, as it has the quality of rapid experiments with mass collections of samples. A complementary and clarifying method is scanning electron microscopy, which makes it possible to establish the bituminous substance in rocks, its interaction with the mineral matrix of the rock and authigenic minerals. Fragments of carbonized matter were studied in coal petrographic thin sections in transmitted light. The composition of microcomponents of organic matter, their transformation and the ability to generate various hydrocarbons have been specified. Thus, comprehensive studies have been carried out to objectively assess the generation potential of DOM in Jurassic rocks. Conclusions: in the J beds, DOM corresponds to types I-II of kerogen, it is catagenetically converted to the stage МКof mesocatagenesis, has good and excellent generation potential and has the ability to generate oil hydrocarbons. DOM of J-J beds corresponds to type II-III mixed kerogen, catagenetically transformed to the МК- МК stage, has a good generation potential and has the ability to generate mainly gas hydrocarbons. Samples of carbonaceous rocks and coal interlayers contain OM corresponding to type III kerogen, catagenetically transformed to the МК-МКstage, has good generation potential and is capable of generating predominantly gas hydrocarbons. (306 words).
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Kotomkin, Alexey V., Natalia P. Rusakova, Vladimir V. Turovtsev, and Yuriy D. Orlov. "ELECTRON PARAMETERS OF 1,1,1 – TRILUOROALKANES." IZVESTIYA VYSSHIKH UCHEBNYKH ZAVEDENIY KHIMIYA KHIMICHESKAYA TEKHNOLOGIYA 62, no. 1 (December 30, 2018): 31–37. http://dx.doi.org/10.6060/ivkkt201962fp.5517.
Full textAbstract:
On the basis of quantum-chemical calculations the properties of trifluoro-substituted hydrocarbon molecules CnH2n+1-CF3 (n ≤ 9) received from their electron density distribution were considered. The geometry optimization of ten structures was carried out. The surfaces of zero flow electron charge density gradient were specified, and the basins of atomic groups and fluorine atoms were found. The electron integral parameters (charges q(R), energies E(R) and volumes V(R)) of atomic groups in trifluoroalkane molecules were calculated and analyzed. The relationship between the length of the hydrocarbon chains and the transferability of the properties of the selected groups (CF3, CH3, CH2) was revealed, that is reflected in their transferable parameters. For the studied homologous series the qualitative group electronegativity scale was made up and inductive effect (I - effect) of fluorine containing group was considered. The attenuation of I – effect in CnH2n+1-CF3 (n ≥ 6) within molecular fragments CF3-(CH2)4 and CH3-CH2 was identified. In this regard, the appearance of the «unperturbed» CH2 group was registered at n > 6. The «standard» (or «transferable») value of the total group energy E(R) was introduced and computing of the relative group energy ΔE(R) was described. It was shown, that the reduction of the volumes of the nearest СН2 to the СF3 was caused by the electron density redistribution. The comparative analysis of the group charges q(R) in CnH2n+1-CF3 (n ≤ 9) with corresponding q(R) in monofluorine alkanes, monofluorine alkane radicals, difluorine alkanes and difluorine alkane radicals was performed. The comparison of the charges of relevant groups and fluorine-containing fragments of the fluoro-substituted nonane and their radicals was presented as graphic dependence, which provides an understanding of the attenuation of I – effect from СF3.
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Rashid, Muhammad, Miao Luo, Umar Ashraf, Wakeel Hussain, Nafees Ali, Nosheen Rahman, Sartaj Hussain, Dmitriy A. Martyushev, Hung Vo Thanh, and Aqsa Anees. "Reservoir Quality Prediction of Gas-Bearing Carbonate Sediments in the Qadirpur Field: Insights from Advanced Machine Learning Approaches of SOM and Cluster Analysis." Minerals 13, no. 1 (December 24, 2022): 29. http://dx.doi.org/10.3390/min13010029.
Full textAbstract:
The detailed reservoir characterization was examined for the Central Indus Basin (CIB), Pakistan, across Qadirpur Field Eocene rock units. Various petrophysical parameters were analyzed with the integration of various cross-plots, complex water saturation, shale volume, effective porosity, total porosity, hydrocarbon saturation, neutron porosity and sonic concepts, gas effects, and lithology. In total, 8–14% of high effective porosity and 45–62% of hydrocarbon saturation are superbly found in the reservoirs of the Eocene. The Sui Upper Limestone is one of the poorest reservoirs among all these reservoirs. However, this reservoir has few intervals of rich hydrocarbons with highly effective porosity values. The shale volume ranges from 30 to 43%. The reservoir is filled with effective and total porosities along with secondary porosities. Fracture–vuggy, chalky, and intracrystalline reservoirs are the main contributors of porosity. The reservoirs produce hydrocarbon without water and gas-emitting carbonates with an irreducible water saturation rate of 38–55%. In order to evaluate lithotypes, including axial changes in reservoir characterization, self-organizing maps, isoparametersetric maps of the petrophysical parameters, and litho-saturation cross-plots were constructed. Estimating the petrophysical parameters of gas wells and understanding reservoir prospects were both feasible with the methods employed in this study, and could be applied in the Central Indus Basin and anywhere else with comparable basins.