Hydrocarbon Storage Capacity Research Articles

Comparative study on pore-connectivity and wettability characteristics of the fresh-water and saline lacustrine tuffaceous shales: triggering mechanisms and multi-scale models for differential reservoir-forming patterns

Although particular attention has been paid to responses of hydrocarbon storage and percolation capacity to the devitrification concerning lacustrine tuffaceous shale reservoirs in recent years, there is still a lack of systematical and comparative investigation on differential patterns and potential triggering mechanisms concerning development of the pore-microfracture systems and characteristics of surface wettability between the fresh-water and saline lacustrine settings, which is of considerable importance in fully understanding of genesis and spatial distribution of dessert reservoir intervals of tuffaceous shale reservoirs, and to provide further conceptual basis for deciphering shale-oil movability of saline lacustrine fine-grained mixed sedimentary sequences. In this study, tuffaceous shales from both the Upper Triassic Yanchang Formation in the Ordos Basin and Middle Permian Jingjingzigou Formation in the Junggar Basin are targeted to unravel the differential behavior of tuff devitrification and potential impacts on reservoir wettability and pore connectivity concerning fresh-water and saline lacustrine settings, and we present new results here from integrated analyses and combined interpretation of FE-SEM, Image Pro Plus (IPP) software image processing, contact angle and spontaneous imbibition experiments. In view of comparative analysis from representative samples, the tuffaceous shales from saline lacustrine environments are characterized by well-developed intergranular-intercrystalline and dissolution pores, and inorganic microfractures, generally yield a higher plane porosity of representative pore-fracture spaces and spontaneous imbibition slopes, a relatively lower average of n-decane contact angles and corresponding wettability parameters. The saline lacustrine tuffaceous shales are thus suspected to have undergone more intense devitrification resulting in a higher amount of devitrification and associated dissolution pores, and a relatively better connectivity between isolated micropore systems with adjacent microfractures. This would significantly facilitate the interface wettability reversal and occurrence of movable hydrocarbon fluid in microscopic reservoir spaces. Finally, a comprehensive and conceptual model is established illustrating the effects of differential devitrification on reservoir-forming patterns concerning tuffaceous shales developed in the fresh-water and saline lacustrine settings, respectively. These findings are of great theoretical and practical significance to enrich theory of high-quality reservoir formation and shale-oil accumulation in saline lacustrine tuffaceous shale reservoirs, and lay the foundation for guiding efficient exploration of continental fine-grained mixed sedimentary sequences.

Correlation between geomechanical and sedimentary facies and their implications for flow unit definition in the pre-salt carbonate reservoir, Brazil

Carbonate reservoirs are of great economic importance due to their frequent association with high permeability and hydrocarbon storage capacity. One of the most significant discoveries of this type of reservoir in recent decades has been the Brazilian Pre-salt. This deep reservoir has unusual depositional features, consisting of a wide variety of textures with different compositions, influenced by diagenetic overprinting that modify most of its mechanical, elastic and petrophysical properties. Despite the marked heterogeneity, these carbonates are characterized by excellent reservoir quality. The objective of this study is to establish a correlation between geomechanical behavior and sedimentary facies and its implications for the definition of flow units in the Barra Velha Formation, the main reservoir of the Brazilian Pre-salt. Thus, using a database from the Buzios field composed of well logs (conventional and advanced), well tests, thin sections, and laboratory petrophysics, geomechanical facies (GMFs) were defined using dynamic geomechanical modeling and an unsupervised algorithm (K-mean clutering), followed by textural classification of sedimentary facies and definition of flow units (FUs) on the decametric scale. These classifications were compared using frequency histograms. The geomechanical model revealed that the in-situ stress state exhibits a dual regime, between normal and strike slip. In addition, it was found that the direction of the maximum horizontal stress is in the NE-SW azimuth. In this context, four geomechanical facies were defined, which showed a notorious variation in mechanical strength. The strongest GMFs consisted mainly of well-cemented Grainstones and Packstones with no apparent porosity or microcrystalline porosity and correlated with the FU with the worst production rates. On the other hand, the weaker GMFs were mainly composed of Grainstones and Spherulistones with high intergranular porosity generated by dissolution processes, with higher risk of pore collapse and correlated with the FUs with the best production rates. However, this classification also identified laminated mudstones with microporosities associated with FUs that act as flow barriers. Geomechanical facies have also been incorporated into reservoir development by evaluating wellbore stability, fault reactivation risk, and brittleness index for future CO2 injection projects.

Vertical displacement of a non-Newtonian Bingham plastic by a Newtonian phase in an axially composite reservoir

In general, oil reservoirs may consist of composite sedimentary structures composed of materials such as sand, clay, or limestone, which exhibit varying lithology due to sedimentary processes. A comprehensive knowledge of this lithology is essential for accurately assessing their hydrocarbon storage and production capacity. Additionally, this information is indispensable for the implementation of various recovery techniques such as waterflooding, gas injection, surfactant injection, polymer injection, alkaline water solution injection, and others. Highly viscous oil can exhibit non-Newtonian behavior during water injection in certain cases. The use of surfactants, alkaline, or polymer solutions in enhanced oil recovery also introduces non-Newtonian behavior. Recovery methods face challenges when non-Newtonian phases, gravity, and reservoir heterogeneity are combined. Against this backdrop, this work presents a mathematical model for immiscible two-phase flow in an axially composite reservoir with a periodic-layered structure. The model considers a non-Newtonian plastic Bingham-type phase extension of the Buckley-Leverett model. To address the porous medium’s heterogeneity with discontinuous flux functions, the numerical solutions were obtained using the Lax-Friedrichs and Lagrangian-Eulerian schemes. The numerical solutions were compared to analytical solutions obtained using an extended version of Oleinik’s geometric construction for discontinuous flux functions. The outcomes display shock and rarefaction waves, as well as a fixed shock due to the porous medium heterogeneity. The numerical results closely correspond with the analytical solutions, seen particularly in the greater accuracy of the Lagrangian-Eulerian method compared to the Lax-Friedrichs method.

Utilizing Differences in Mercury Injection Capillary Pressure and Nuclear Magnetic Resonance Pore Size Distributions for Enhanced Rock Quality Evaluation: A Winland-Style Approach with Physical Meaning

Pore structure is a fundamental parameter in determining the hydrocarbon storage capacity and flow characteristics of a reservoir. Mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) are two commonly utilized techniques for characterizing rock pore structures. However, current studies indicate that disparities in testing methodologies due to distinct physical characteristics lead to a partial misalignment in pore size distributions. We conducted MICP (dynamic) and NMR (static) experiments on eight tight sandstone and eight shale samples and proposed a method to utilize information from the differences in MICP and NMR pore size distributions, aiming to enhance the accuracy of rock quality analysis. We observed that in rock cores where large pores are interconnected with smaller pore throats, MICP tends to overestimate the proportion of these smaller pores and underestimate the larger ones. Furthermore, we integrated information from both dynamic and static experimental processes based on physical significance and found that the fitting accuracy of the newly proposed method is superior to the Winland r35 equation. Compared to the Winland r35 equation, our new method significantly improves fitting accuracy, increasing the R-squared value from 0.46 to 0.93 in sandstones and from 0.80 to 0.87 in shales. This represents a potential high-precision, comprehensive tool for rock quality analysis, offering a new perspective for an in-depth understanding of rock properties.

MID CRETACEOUS SUBSURFACE CARBONATE DEPOSIT AND RESERVOIR DEVELOPMENT OF THE MFAMOSING LIMESTONE CALABAR FLANK

This research analyzed the reservoir quality of the Mfamosing Limestone with a view to classifying it as a potential reservoir rock within the Calabar Flank. Materials used in this research are processed seismic data acquired around the Calabar flank and well logs of three wells (A, B, C) drilled at different periods within the study area, core as well as mud log data. The procedure used involved prospect identification and mapping, structural and stratigraphic analysis, reservoir quality and classification of the carbonate rock in the study area. The results were analyzed and classified the Mfamosing Limestone using hydrocarbon storage capacity and deliverability potential. Wells A and B was drilled 0.8km apart and well C drilled 4.7km from well B which encountered the Mfamosing Limestone with logs indicating hydrocarbon in Well A which had a shallower sandstone lenses. The sandstone lens in Well A was tested for hydrocarbon and flowed briefly and stopped. Wells B and C were planned and drilled using Well A as reference amongst other parameters to evaluate the hydrocarbon potential of the Mfamosing Limestone. Wells B and C were found completely dry. Two conventional coring runs at depths 10,490ft-10,552.5ft and 10,552.5ft-10,614ft in Well B indicated that the cored intervals are light grey, moderate to very hard, and fossil rich limestone with no direct fluorescence. The core analysis results suggest that limestone is dry and highly indurated with no evidence of physical porosity. This suggest that the Mfamosing Limestone penetrated by all three wells though massive has no hydrocarbon storage capacity and deliverability potential typical of a reservoir rock. This research therefore suggests that the Mid Cretaceous subsurface Mfamosing Limestone is more of a mineral carbonate deposit than a hydrocarbon reservoir.

Petroleum system modeling in complex tectonic setting; a study case of the Huallaga-Marañon retroforeland basin system, Peru

The present study explores the oil and gas potential of the Huallaga–Marañon Andean retroforeland basins in Perú, considering a regional transect which extends from the Eastern Cordillera in the west trough the Huallaga fold-and-thrust belt at the Andean deformation front to the Marañon Basin in the east. The sequential restoration of main tectonic events was derived from previous stratigraphic and structural interpretations revisited with reprocessed seismic lines, and new geochemical, petrographical, geochronological and thermochronological data. The resulting framework was tested in a 2-D Basin and Petroleum System Modeling (BPSM) to check the relationship between burial history, thermal maturity evolution and timing of hydrocarbon generation, expulsion and trapping at regional scale. BPSM suggests that during the Late Cretaceous (ca. 80 Ma) the petroleum generated in the Upper Triassic–Lower Jurassic source rock known as the Aramachay Formation migrated through the Middle–Upper Jurassic Sarayaquillo Formation basal sandstones up to 250 km and accumulated in the southeast of the Marañon Basin. From the Late Miocene, the reactivation of vertical faults favored the migration and accumulation of petroleum in Cretaceous siliciclastic reservoirs which is consistent with the hydrocarbon fields existence in this sector of the basin.In addition, results of modeling show that in the southwest of the Marañon Basin the development of structures during Late Miocene times postdated the generation and expulsion of hydrocarbons calculated for the Aramachay Formation which introduces a risk of synchronization between oil migration and charge. However, part of the generated hydrocarbons during the Late Cretaceous and Cenozoic are partially preserved in Jurassic reservoirs due to the high seal capacity of mudstones of the Sarayaquillo Formation. Such hydrocarbon fluids are redistributed and migrated into structural traps during Miocene times. In addition, the Miocene gas generation and expulsion also will reduce the risk of synchronization with the development of structures. In the Eastern Cordillera, organic-rich levels of the Aramachay Formation are in the late immature to early oil window show the occurrence of organic pores adding hydrocarbon storage capacity, suggesting this unit to be considered as a potential unconventional target in future exploration activities.

The Impact of Lanthanum and Zeolite Structure on Hydrocarbon Storage

Hydrocarbon traps can be used to bridge the temperature gap from the cold start of a vehicle until the exhaust after-treatment catalyst has reached its operating temperature. In this work, we investigate the effect of zeolite structure (ZSM-5, BEA, SSZ-13) and the effect of La addition to H-BEA and H-ZSM-5 on the hydrocarbon storage capacity by temperature-programmed desorption and DRIFT spectroscopy. The results show that the presence of La has a significant effect on the adsorption characteristics of toluene on the BEA-supported La materials. A low loading of La onto zeolite BEA (2% La-BEA) improves not only the toluene adsorption capacity but also the retention of toluene. However, a higher loading of La results in a decrease in the adsorbed amount of toluene, which likely is due to partial blocking of the pore of the support. High loadings of La in BEA result in a contraction of the unit cell of the zeolite as evidenced by XRD. A synergetic effect of having simultaneously different types of hydrocarbons (toluene, propene, and propane) in the feed is found for samples containing ZSM-5, where the desorption temperature of propane increases, and the quantity that desorbed increases by a factor of four. This is found to be due to the interaction between toluene and propane inside the structure of the zeolite.

Shale lithofacies controls on porosity and pore structure: An example from Ordovician Goldwyer Formation, Canning Basin, Western Australia

The hydrocarbon storage and transport capacity of shale reservoirs are dependent on its complex pore systems. This study focuses on Ordovician Goldwyer Formation (Goldwyer shale) from Canning Basin, Western Australia. Multi-scale qualitative (X-ray diffraction, field emission scanning electron microscope, TESCAN integrated mineral analyser (TIMA) and thin-section analysis) and quantitative (Rock-Eval® pyrolysis, helium porosity on crushed samples, low-pressure gas adsorptions (N2 and CO2) and mercury injection capillary pressure (MICP)) approaches were applied on shale samples. The results indicate that the Goldwyer shale comprises five main lithofacies (namely organic-rich shale, argillaceous shale, siliceous shale, calcareous shale, and mixed shale) based on mineral composition and total organic carbon (TOC) content. The organic-rich and siliceous shales have highest porosity (>10%) followed by mixed shale and other lithofacies. Three types of pores, namely organic pores, interparticle, and intraparticle pores, are identified in Goldwyer shale. Most of the pores are narrow slit-like or bottle-necked shaped pores. The micropore and mesopore volumes and specific surface area (SSA) of all lithofacies are positively related to TOC except for the argillaceous shale. Conversely, the micro and mesopore parameters (SSA and pore volumes) exhibited inverse relations with total clay content for all lithofacies except argillaceous shale. This indicates that the total clay and TOC content is the main controlling factors for pore structure of Goldwyer shale. The whole pore aperture exposed that mesopores are more abundant in Goldwyer shale; however, few micro and macropores are also found in different lithofacies. The organic-rich, siliceous and mixed shales could be deemed as the most essential lithofacies types for fluid flow via pore systems due to high porosity and feasible pore structures.

Origin and implications of early diagenetic quartz in the Mississippian Bowland Shale Formation, Craven Basin, UK

Silica cementation exerts a key control on the compaction and geotechnical properties of mudstones, and by extension, the style of hydrocarbon and/or mineral systems present in a given sedimentary basin. Integrated microscopic and bulk geochemical observations demonstrate that siliceous mudstones in the Bowland Shale Formation, a target for UK shale gas extraction, exhibit abundant dispersed, discrete, μm-scale quartz cements, and exhibit silica enrichment (‘excess’) above a local detrital Si/Al threshold of 2.5. Dissolution of siliceous radiolarian tests during early diagenesis is identified as the main source of silica (opal A) required for quartz precipitation, either via opal CT or directly to quartz, and potentially generated as a product of anoxic marine ‘weathering’ (dissolution) of reactive silicates during early diagenesis. Excess silica correlates with free hydrocarbons (S1) normalised to total organic carbon (oil saturation index; OSI); we propose early diagenetic quartz precipitation suppressed pore collapse (‘buttress effect’), retaining the pore space capacity to host oil. Quartz precipitation was likely catalysed, for example via low porewater pH, elevated Al and/or Fe oxide content, and/or abundant labile organic matter. Juxtaposition of siliceous mudstones and mudstones lacking quartz cement indicates silica was immobile beyond the bed scale. Thus metre-scale siliceous packages likely represent more prospective units within the Bowland Shale (in terms of unconventional hydrocarbons), on the basis of early diagenetic biogenic-derived quartz cementation leading to improved hydrocarbon storage capacity coupled to enhanced brittleness. These findings are relevant for shale oil and shale gas systems, specifically where oil retained in pores subsequently cracks to generate gas. These findings also suggest the Bowland Shale is a sub-class of black shale, defined by the potential to host a relatively large volume of early diagenetic fluids, derived from anoxic bottom waters, which were potentially S- and/or metal-bearing. This is potentially relevant for understanding the genesis of adjacent and related Pb-Zn mineral deposits.

Properties and shale gas potential of continental shales in the Jurassic Mohe Foreland Basin, northern China

Reservoir properties and shale gas potential of the Upper Jurassic continental shales from the Mohe Foreland Basin were investigated based on organic geochemical analysis, X‐ray diffraction, scanning electron microscopy, low pressure nitrogen adsorption, high pressure mercury injection, and porosity and permeability analyses. The results indicate that the shallow lacustrine shales of the Emuerhe Formation are characterized by high total organic carbon content (0.43–22.83 wt.%), low hydrocarbon generative potential (less than 5.0 mg HC/g rock), type II kerogen, and a moderate thermal maturity stage (Ro of 1.05–1.46%). The inorganic pores dominate the pore system, and pores associated with clay minerals largely contribute to the surface area. The inorganic pore‐dominated lacustrine shale reservoir is characterized by dense, low porosity, and poor connectivity. The shales of the Emuerhe Formation show strong heterogeneity in mineralogy and are relatively enriched in clay minerals (33–66 wt.%). Due to the lack of biogenic silica, the effect of brittle minerals on hydraulic stimulation is ambiguous in the shallow lacustrine shales. The widely distributed, extensionally unfilled fractures can not only enhance hydrocarbon storage and migration capacity, but also play an important role in the generation of artificial reservoir fracturing. The pore network of lacustrine shales contributed by inorganic pores and unfilled micro‐fractures could also generate a relatively high porosity and permeability. The high‐mature thick shales in the northwest area of the Xingan Town would be the favourable zone for the shale gas exploration and exploitation in the Mohe Foreland Basin.

Pore structures of different types of shales and shale gas exploration of the Ordovician Wufeng and Silurian Longmaxi successions in the eastern Sichuan Basin, South China

Shales from Ordovician Wufeng and Silurian Longmaxi groups in the Sichuan Basin were analyzed by using the field emission-scanning electron microscopy, helium pycnometry, and low-pressure gas adsorption experiments. There are mainly three lithofacies in the studied shale reservoirs: clay-rich siliceous shale (S-3), argillaceous/siliceous mixed shale (M-2), and silica-rich argillaceous shale lithofacies (CM-1). The organic-rich S-3 shales have the highest porosity (averaging 5.4%), the largest pore volume (averaging 0.024 mL/g), and the highest specific surface area (averaging 21.6 m2/g). Organic matter (OM) pores contribute 62.6% to the porosity of S-3 shales. M-2 shales have the moderate pore structure with porosity averaging 4.3%, pore volume averaging 0.019 mL/g, and specific surface area averaging 16.7 m2/g. Organic matter and clay minerals contribute 49.5% and 36.8% to the porosity of M-2 shales, respectively. The CM-1 shales have the lowest porosity (averaging 4.1%), the smallest pore volume (averaging 0.017 mL/g), and the lowest specific surface area (averaging 15.6 m2/g). The organic-lean CM-1 shales are dominated by clay mineral pores. Clay minerals contribute 56% to the porosity of CM-1 shales.OM pores are well developed in the S-3 shale lithofacies, while most of OM pores are destroyed or compacted in CM-1 shale lithofacies. The effect of compaction on porosity of CM-1 shales is stronger than that of M-2 and S-3 shales because of the highest clay minerals content and the lowest siliceous minerals content. Considering the pore spaces and hydraulic fracturing operation, the S-3 shales is more suitable to shale gas exploration than M-2 and CM-1 shales. Certainly, the M-2 and CM-1 shales also have certain amounts of hydrocarbon storage capacity, and could be considered as the candidate targets for shale gas exploitation.

Unidades de flujo a partir del indicador de zona de flujo (FZI) considerando el modelo petrofísico para yacimientos sub-saturados

En la industria petrolera se cumplen varios parámetros en diversas etapas para realizar exploraciones y explotaciones de un yacimiento petrolero. Esas etapas comprenden la ejecución de gran variedad de estudios técnicos, geológicos, petrofísicos además de realizar un estudio en la caracterización de yacimientos el mismo que se enfoca a obtener la información necesaria que conduzca a una explotación adecuada del mismo. El propósito es determinar las unidades de flujo a partir del Indicador de la Zona de Flujo (FZI) considerando el modelo petrofísico de un yacimiento sub-saturado de la cuenca del lago de Maracaibo-Venezuela con la técnica basada en una modificación de la ecuación de Kozeny- Carmen, dándole la importancia que merece a la petrofísica ya que esta define los parámetros necesarios para tener resultados favorables, de igual manera se hace la lectura de registros que juegan un papel fundamental para la investigación. Se seleccionaron propiedades del yacimiento sub-saturado para la elaboración del mismo, luego se estableció los parámetros del modelo petrofísico para conocer el tipo, calidad de roca, densidad de matriz de formación, parámetros de corte, la arena neta petrolífera, arena neta total, conocer el Petróleo Original En Sitio (POES) a través del método volumétrico y de balance de materia. Una vez obtenidos todos los puntos necesarios se puso en marcha un modelo matemático que establece las unidades de flujo a partir del indicador de zona, este se realiza en 2 pozos seleccionados los mismos que son: LL-0773, LL-0848 cada uno con sus profundidades estableciendo la capacidad de almacenamiento de hidrocarburo del yacimiento sub-saturado para su explotación y comercialización quedando como referencia para nuevos estudios que consideren todos los parámetros para llegar al objetivo principal.

Effects of Multicomponent Hydrocarbon Feed on Hydrocarbon Adsorption–Desorption and Oxidation Light-Off Behavior on a Pd/BEA Hydrocarbon Trap

A model hydrocarbon trap material consisting of palladium promoted zeolite beta on a monolith core was studied with a multicomponent hydrocarbon feed. Dodecane and ethylene adsorption, followed by temperature programmed oxidation (TPO), was used in the presence of CO in wet and dry conditions to study the impact of various species on hydrocarbon storage, oxidation, and desorption. Low temperature adsorption experiments were used to quantify hydrocarbon storage capacity, while temperature programmed desorption (TPD) and TPO studies were used to investigate both oxidation and desorption of the various hydrocarbon species. The low temperature adsorption experiments suggest a moderate impact of water on dodecane uptake as dry experiments adsorbed more dodecane overall than those under wet conditions. Additionally, the presence of CO and ethylene also impaired dodecane uptake. TPD studies indicated a coupled relationship between hydrocarbon oxidation light-off and desorption. By varying the composition of the feed, specifically via the inclusion of CO or ethylene, dodecane oxidation light-off was delayed, which actually increased the overall hydrocarbon trap efficiency.

Nano-Scale Pore Structure and Fractal Dimension of Longmaxi Shale in the Upper Yangtze Region, South China: A Case Study of the Laifeng–Xianfeng Block Using HIM and N2 Adsorption

This paper tries to determine the key evaluation parameters of shale reservoirs in the complex tectonic provinces outside the Sichuan Basin in South China, and also to target the sweet spots of shale reservoirs accurately. The pore-structure characteristics of the Lower Silurian Longmaxi shale gas reservoirs in Well LD1 of the Laifeng–Xianfeng Block, Upper Yangtze region, were evaluated. N2 adsorption and helium ion microscope (HIM) were used to investigate the pore features including pore volume, pore surface area, and pore size distribution. The calculated results show good hydrocarbon storage capacity and development potential of the shale samples. Meanwhile, the reservoir space and migration pathways may be affected by the small pore size. As the main carrier of pores in shale, organic matter contributes significantly to the pore volume and surface area. Samples with higher total organic carbon (TOC) content generally have higher porosity. Based on the Frenkel–Halsey–Hill equation (FHH model), two different fractal dimensions, D1 and D2, were observed through the N2 adsorption experiment. By analyzing the data, we found that large pores usually have large values of fractal dimension, owing to their complex pore structure and rough surface. In addition, there exists a good positive correlation between fractal dimension and pore volume as well as pore surface area. The fractal dimension can be taken as a visual indicator that represents the degree of development of the pore structure in shale.

Fractal analysis of the pore structure for clay bound water and potential gas storage in shales based on NMR and N2 gas adsorption

Abstract Fractal dimension (D) is a critical parameter to estimate the heterogeneity of complex pore structure in shale gas reservoirs. To quantify the fractal dimension of various pore types and evaluate their implications on shale effective porosity and gas storage capacity in potential, we performed fractal analysis based on experimental results of low-field nuclear magnetic resonance (LF-NMR) and low-pressure N2 gas adsorption (LP-N2-GA) in Permian Carynginia shales. By comparing the calculated fractal dimensions based on the two approaches, we analyzed the 'surface fractal dimension' for ineffective pores occupied by clay bound water (CBW) and the 'volume fractal dimension' for effective pores (Deff) holding removable fluids for the first time in shales. The NMR-based CBW pore fractal dimension (Dcbw) is linear positively correlated with the fractal dimension of micropore surface (D1) (R2 = 0.91) and the volume of CBW (R2 = 0.58), while negatively correlated with effective porosity (R2 = 0.58). The NMR-based effective pore fractal dimension (Deff) is linear positively correlated with the fractal dimension of meso/macropore volume (D2) (R2 = 0.82) and presents a good positive correlation with gas storage capacity (R2 = 0.80). The results indicate that CBW largely complicates the fractal geometry of nanoscaled pore network and potentially resist effective fluid flows in shales. The pore surface of higher heterogeneity (higher D1) associates with larger surficial CBW retention and would further block the effective pore space for fluid transport. The meso/macropore volumes of higher complexity (higher D2) is intimate with the larger heterogeneity in effective pores for the higher potential of hydrocarbon storage capacity in gas shales.

Integration of Electrofacies and Hydraulic Flow Units to Delineate Reservoir Quality in Uncored Reservoirs: A Case Study, Nubia Sandstone Reservoir, Gulf of Suez, Egypt

Recognition of reservoir quality is an important objective in reservoir characterization process. By definition, the quality of a reservoir is described by its hydrocarbon storage capacity and deliverability. The storage capacity is a function of porosity, whereas deliverability is a function of permeability. Thus, both porosity and permeability are the main reservoir quality controlling factors. Five wells were selected to study the reservoir quality of the Nubia sandstone in the Gulf of Suez, Egypt. The Nubia interval, deposited in continental to shallow marine conditions, consists mainly of sandstone intercalated by thin layers of shale. Three wells were partially cored and the other two wells are completely uncored. Based on several complementary techniques, it is concluded that the Nubia sandstone is of moderate to extremely heterogeneous quality. The porosity–permeability cross-plot showed fair-to-medium relationship, indicating the significant role of diagenetic agents. The Nubia reservoir quality has been enhanced principally by fracturing, dissolution and leaching. However, the reservoir quality decreased by cementation, compaction and filling of pore spaces by kaolinite. Based on principal component and cluster analyses, six electrofacies are recognized within the Nubia interval. Three electrofacies are dominant, whereas the other three are subsidiary. Flow zone indicator (FZI) was determined based on mean hydraulic radius and normalized porosity. Correlation between electrofacies and FZI permits discriminating the subject formation into reservoir quality ranks. The relative complexity of this reference formation notwithstanding, because of the robustness of the resulting electrofacies–FZI correlations, it was relatively straightforward to recognize and reasonably predict the reservoir quality of the uncored intervals.

Effect of Functional Groups on the Adsorption of Light Hydrocarbons in fmj-type Metal–Organic Frameworks

The functionalized modification of targeted porous metal–organic frameworks (MOFs) is important to improve the adsorption capacity of light hydrocarbon gases. Five isomorphic MOFs with different functional groups (F, Cl, NH2, CH3, and OCH3) are successfully synthesized by systematic functional modification of UMCM-151. By studying the adsorption properties of C2 and C3 hydrocarbons (C2H2, C2H4, C2H6, C3H6, and C3H8), it is found that the electron-withdrawing group functional UMCM-151-F and UMCM-151-Cl exhibit strong affinity for C2H2 (98.71 cm3 g–1 for UMCM-151-F and 90.29 cm3 g–1 for UMCM-151-Cl), while the electron-donating group functional UMCM-151-NH2, UMCM-151-CH3, and UMCM-151-OCH3 have strong affinity for C2H4 (97.89 cm3 g–1 for UMCM-151-NH2, 90.22 cm3 g–1 for UMCM-151-CH3 and 94.13 cm3 g–1 for UMCM-151-OCH3). The differences in affinity of electron effects for light hydrocarbon provide an experimental basis for porous MOFs to improve their light hydrocarbon storage capacity.

Integration of Open Metal Sites and Lewis Basic Sites for Construction of a Cu MOF with a Rare Chiral Oh -type cage for high performance in methane purification.

A Cu metal-organic framework (MOF), [Cu4 (PMTD)2 (H2 O)3 ]⋅20 H2 O, 1, (where PMTD is 1,4-phenylenebis(5-methyl-4H-1,2,4-triazole-3,4-diyl)bis(5-carboxylato-3,1-phenylene)bis(hydroperoxymethanide)), with a rare chiral Oh -type cage, and dual functionalities of open metal sites and Lewis basic sites, based on a designed U-shaped ligand, was synthesized by hydrothermal methods. It exhibits high CO2 , C2 , and C3 hydrocarbon storage capacity under atmospheric pressure, as well as high H2 (1.96 wt.%) adsorption capacity at 77 K. Methane purification capacity was tested and verified step by step. Isosteric heats (Qst ) studies reveal that CH4 has the weakest van der Waals host-guest interactions among the seven gases at 298 K. Ideal adsorbed solution theory (IAST) calculation reveals that compound 1 is more selective toward CO2 , C2 H6 , and C3 H8 over CH4 in further calculating its separation capacity, as exemplified for CO2 /CH4 (50:50, 5:95), C2 H6 /CH4 (50:50, 5:95), or C3 H8 /CH4 (50:50, 5:95) binary gas mixtures. Breakthrough experiments show that 1 has a significantly higher adsorption capacity for CO2 , C2 H6 , and C3 H8 than CH4 . The selective adsorption properties of 1 make it a promising candidate for methane purification.

An Effective Reservoir Parameter for Seismic Characterization of Organic Shale Reservoir

Sweet spots identification for unconventional shale reservoirs involves detection of organic-rich zones with abundant porosity. However, commonly used elastic attributes, such as P- and S-impedances, often show poor correlations with porosity and organic matter content separately and thus make the seismic characterization of sweet spots challenging. Based on an extensive analysis of worldwide laboratory database of core measurements, we find that P- and S-impedances exhibit much improved linear correlations with the sum of volume fraction of organic matter and porosity than the single parameter of organic matter volume fraction or porosity. Importantly, from the geological perspective, porosity in conjunction with organic matter content is also directly indicative of the total hydrocarbon content of shale resources plays. Consequently, we propose an effective reservoir parameter (ERP), the sum of volume fraction of organic matter and porosity, to bridge the gap between hydrocarbon accumulation and seismic measurements in organic shale reservoirs. ERP acts as the first-order factor in controlling the elastic properties as well as characterizing the hydrocarbon storage capacity of organic shale reservoirs. We also use rock physics modeling to demonstrate why there exists an improved linear correlation between elastic impedances and ERP. A case study in a shale gas reservoir illustrates that seismic-derived ERP can be effectively used to characterize the total gas content in place, which is also confirmed by the production well.

Impact of Zeolite Beta on Hydrocarbon Trapping and Light-Off Behavior on Pt/Pd/BEA/Al2O3 Monolith Catalysts

The impact of large-pore zeolite beta (BEA) on the performance of model monolithic Pt/Pd/Al2O3 diesel oxidation catalyst is investigated in terms of hydrocarbon (HC) storage capacity, light-off, and oxidation. Dodecane (C12) is employed as the model HC to elucidate BEA loading impact on catalyst performance during temperature-programmed oxidation of CO and C12 and mixtures in the absence of feed water. A C12 pre-storage experiment protocol quantifies storage at room temperature, the effect of C12 storage on light-off temperature, and the extent of release and conversion of C12. The temperature ramp experiments indicate a negligible impact of the zeolite on the individual reactant (CO and C12) light-offs. Co-feed experiments (HC + CO simultaneous feed) reveal light-off inhibition by CO and C12 in addition to that by pre-stored C12. This trend is consistent for all zeolite loading levels. During both co-feed and C12 pre-storage experiments, an intermediate zeolite loading results in a decreased CO light-off temperature when compared to the zeolite-free catalyst. This beneficial effect is attributed to the zeolite providing alternative storage sites for the HC, thereby mitigating the inhibition on the CO light-off by freeing up precious metal sites for CO oxidation. However, the highest zeolite loading catalyst has an increased CO light-off temperature in C12 pre-storage experiments compared to the catalyst with intermediate loading. This trend reversal is attributed to the kinetic and/or transport inhibitory effect of stored C12 which overcomes the enhancement at lower loadings. The data indicate that the highest zeolite loading yields the highest percentage of stored C12 converted to CO2, a finding relevant for HC trap catalyst design. The study findings suggest a need to optimize the zeolite loading for the desired operating conditions to achieve desired light-off and HC trapping and conversion. The impact of feed water will be investigated in future work to evaluate the generality of these findings.