Presence Of Sandstone Research Articles

Deciphering minerals in reservoir rocks as natural catalysts for in-situ methane-to-hydrogen conversion via electromagnetic heating

Electromagnetic (EM)-assisted catalytic heating for in-situ hydrogen generation directly from petroleum reservoirs is an emerging method for decarbonizing petroleum industry and facilitating energy transition. Lab-scale experiments have shown that hydrogen generated from methane cracking in the presence of sandstone via EM heating can reach up to a concentration of 91 mol.% at 668 °C. However, the role of various minerals in reservoir rocks during this process remains poorly understood. This study aims to decipher the natural catalytic effects of minerals of reservoir rocks, such as quartz, kaolinite, illite, chlorite, etc., in catalyzing methane conversion to hydrogen under EM irradiation. Our findings demonstrate that kaolinite exhibits the strongest catalytic activity, starting to generate hydrogen at 331 °C and achieving a 73% methane conversion at 450 °C, while chlorite and albite also showing notable activity with hydrogen being generated below 500 °C. Furthermore, this study quantifies the catalytic contributions of metal oxides, Na+ in albite, Fe2+ and Mg2+ in chlorite and illite, and Al3+ in kaolinite, in promoting methane conversion to hydrogen. By deciphering the catalytic role of minerals and metal oxides, this research offers crucial insights for future optimization of field-scale H2 production from gas reservoir by leveraging the minerals of reservoir rocks as natural catalysts.

Experimental study on hydraulic fracture propagation behavior in heterogeneous shale formations

The study of fracture propagation in heterogeneous shale is a crucial prerequisite for the investigation of heterogeneous cluster and perforation parameters optimization. In this paper, we conduct a physical simulation fracturing experiment on heterogeneous shale to investigate the effects of various influencing factors, such as shale bedding, near-wellbore fractures, lithological changes, and the presence of fractures surrounding the perforation hole, on fracture propagation law and morphology. Our research demonstrates that during shale fracturing, shear dislocation typically occurs between layers, resulting in the separation of different layer planes. The main fracture primarily propagates through layers in a stepped manner. The presence of sandstone in heterogeneous shale significantly impedes fracturing fractures, causing significant distortion and deviation. As the scale of natural fractures increases, it tends to cause the fracturing fracture to twist and change direction. The natural fractures network can also lead to the distortion of fracturing fractures, albeit to a lesser extent than large-scale natural fractures. The presence of micro fractures parallel to the perforation axis surrounding the perforation hole enhances the ability of the main fracturing fractures to pass through natural fractures.

Effect of silica nanoparticles on crude oil emulsions stabilized by a natural surfactant from Fenugreek Seeds and polyacrylamide for subsurface oil mobilization applications

Emulsions represent a sustainable method for subsurface resource recovery due to their superior performance in pore plugging, mobility control and interfacial tension reduction. However, the stability of emulsion plays a vital role in determining the success of field implementation. In this work, a novel formulation is reported for emulsions wherein they have been stabilized by natural surfactant extracted from fenugreek seed. In this work, two emulsion systems are reported, that is surfactant polymer and nanoparticle-surfactant-polymer emulsion. Surfactant-polymer emulsions are stabilized by natural surfactant whereas nanoparticle-surfactant-polymer emulsion are stabilized in presence of nanoparticle and natural surfactant. Both the emulsions exhibit shear thinning profile as observed from rheological studies. Nanoparticle-surfactant-polymer emulsions were found to be thermally stable than that of Surfactant-polymer emulsions as evident from microscopic and rheological studies. An increase in temperature has the unfavorable impact on surfactant-polymer emulsion as huge drop in viscosity profile was observed. The viscosity profiles of nanoparticle-surfactant-polymer emulsions were found to be best fitted by the Krieger-Dougherty model with the value of coefficient correlation R2 = 0.99. The contact angle studies showed that NSP solution can reduce the contact angle to much lower value, which is 111˚ to 30˚ whereas surfactant-polymer solution was able to reduce from 116˚ to 57˚ only. Adsorption of silica nanoparticle was also observed in presence of sandstone and decrease in 27.32 % of peak absorbance was observed in span of 20 days. Therefore, finding of the study indicates that nanoparticle-surfactant-polymer emulsions has potential to perform better than surfactant-polymer emulsions, even at elevated temperature, and can be a better and cost-effective alternative to the conventional emulsions used in oilfield applications.

Yanovstan formation of Western Siberia: Lithology, structure, and correlation of deposits

Research subject. Yanovstan f ormation ( J3-K1jnv) of Kimmeridgian-Early Beriasian age. Aim. To identify structural features of the Yanovstan formation, to carry out a detailed correlation of its deposits, including the development of criteria for determining the boundaries of the suite. Materials and methods. The studies were carried out on the basis of borehole data, including core material from 5 boreholes and borehole logging data from 209 boreholes. The borehole logging complex comprised the following methods: gamma ray logging, neutron gamma ray logging, acoustic logging, caliper logging, as well as apparent resistivity and self-polarization logging. The borehole sections were correlated by tracing individual sections of the geological section, which are characterized by relatively stable geophysical parameters. Additionally, a sequence stratigraphic approach was used. Results. The boundaries between the Sigov and Yanovstan formations were identified based on the description of core material and its comparison with the borehole logging data. The Yanovstan formation was subdivided into three units proposed by the authors: lower (ЯНв), middle (ЯНб), and upper (ЯНa). A borehole correlation of the units of the formation was carried out, on the basis of which maps of the total thickness and net-to-gross ratio and the structural plan of each of the identified stratigraphic units were constructed. It was determined that the total thickness of the lower unit reaches 80 m and is characterized by maxima within the eastern part of the study area. The thickness of the upper unit reaches 240 m and is identified within the northeastern part of the area. This part is represented by a predominantly clay composition. The total thickness of the formation as a whole varies from 40 m in the west to 320 m in the northeast. The thicknesses of the middle unit are relatively consistent throughout the study area. The sandiness of the lower unit varies from 0 to 0.27 units; the upper ranges within 0–0.45 units. The middle unit is not characterized by the presence of sandstones. Conclusions. The theory about the supply of sedimentary material during the sedimentation of the suite from paleomounts within the eastern edge of the West Siberian Jurassic paleobasin was confirmed. An assumption was made that the increased thickness of the predominantly clayey suite within the northeastern part of the study area is associated with the redistribution and transfer of terrigenous material carried from the Siberian land by currents moving unidirectionally along the coast (counterclockwise). These currents thus seized the lightest (clayey) material and transported it to the northern part of the basin.

Density functional theory assessed molecular insights into asphaltene interactions within silica and calcium carbonate surface with deep eutectic solvents

Deep Eutectic Solvents (DES) have gained recent attention as asphaltene solvents due to their low cost and eco-friendliness. However, identifying the intermolecular behavior of asphaltene with different DESs using experimental methods is costly and time-consuming. Therefore, this study investigates the intermolecular interactions and electronic properties of DESs with model asphaltene in the presence of sandstone (SiO2) and carbonate (CaCO3) surfaces using Density Functional Theory (DFT) calculations. The study focuses on understanding the binding energies, interaction energies, band gap, and intermolecular mechanism between SiO2 surface, asphaltene, and DESs (SiO2-Asp-DESs systems) and CaCO3 surface, asphaltene, and DESs (CaCO3-Asp-DESs systems). The investigation yields valuable insights into the interactions, stability, and affinity of the asphaltene and DES in the overall system, enhancing understanding of asphaltene behavior in solvent environments. The study shows that DES containing choline chloride as a hydrogen bond acceptor (HBA) outperforms in the presence of both surfaces (SiO2 and CaCO3) with asphaltene. For the SiO2-Asp-DES system, which contains DES as choline chloride and ethylene glycol, a higher intermolecular interaction energy of − 747.174 kJ/mol is observed. In contrast, for the CaCO3-Asp-DES system, DES as choline chloride and glycerol show higher intermolecular interaction energy of − 259.154 kJ/mol. Variations in interaction and binding energies for the systems further show that the effectiveness of DES with asphaltene varies depending on the type of surface (SiO2/CaCO3). As for the overall reactivity, CaCO3-Asp-DESs systems show comparatively less reactivity than SiO2-Asp-DESs systems that show smaller band gaps.

Compositional Simulation, Artificial Intelligence Optimize Water Injection

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198995, “Low-Salinity Water-Injection Optimization in the Namorado Field Using Compositional Simulation and Artificial Intelligence,” by Diana Mercado Sierra, SPE, Argenis Alvarez Rojas, and Victor Salazar Araque, Computer Modelling Group, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, 27-31 July, Virtual. This paper has not been peer reviewed. The complete paper discusses optimization of a development plan involving low-salinity water injection (LSWI). This methodology combines compositional simulation and a mathematical optimization tool that uses artificial intelligence to maximize the net present value (NPV) of the project under evaluation. The adapted methodology allowed an optimal development plan, considering the uncertainty associated in the reservoir, by use of multiple geostatistical realizations and simultaneous history-matched models. LSWI LSWI is an enhanced-oil-recovery technique in which the salinity of the injected water is controlled with the objective of increasing the recovery factor. Of the mechanisms proposed for LSWI, wettability alteration is the most widely accepted for describing the increase of the recovery factor. The wettability change in reservoirs with the presence of sand-stones mainly is attributed to the multionic exchange between the injected fluid and the clay surface, as is the double layer expansion. From a technical point of view, the LSWI success is related strongly to reservoir lithology. An integrated analysis and optimization study was performed using numerical simulation to evaluate LSWI as an alternative for increasing the recovery factor in the Namorado field in the Campos Basin of Brazil.

Taxonomic composition of the latest Carboniferous–earliest Permian smaller foraminifers in the Sanandaj-Sirjan Zone, Iran: New insights about palaeobiogeography, palaeoclimate and paleoecology of the northern margin of the Palaeotethys

The taxonomic diversity of smaller foraminiferal faunas of the uppermost Carboniferous–lowermost Permian (upper Gzhelian–lower Asselian interval) has been accurately investigated in the Sanandaj-Sirjan Zone, Iran. They predominantly contain three foraminiferal classes: Fusulinata, Miliolata and Nodosariata, and six orders: Tuberitinida, Earlandiida, Archaediscida, Endothyrida, Cornuspirida, and Nodosariida. The presence of some remarkable taxa in palaeobiogeography such as Hemidiscus carnicus, that is reported for the first time in Iran, along with Rectogordius is noticeable. Furthermore, these smaller foraminifers are associated with significant fusulinid genera including Praepseudofusulina, “Nonpseudofusulina”, Pseudoschwagerina, and “Schellwienia?”, which indicated that during the latest Gzhelian–Asselian, the Sanandaj-Sirjan Zone was in the northern margin of the Palaeotethys, in a relatively low latitudinal position (ca. 30°S), with warm and humid conditions. This claim can also be evidenced by the presence of sandstones with high degree of chemical weathering, together with the limonite accompanied with a palaeosol in the Upper Carboniferous strata. The presence of a red earthy laterite with lenses of pisolitic bauxite along with a piece of fossil wood in the lowermost Permian beds, confirms the Peri-Tethyan position of the Sanandaj-Sirjan Zone during this period. This study also shows that the first appearance of Frondicularia in the Iranian material, that is the latest Gzhelian–early Asselian, is probably older than what is argued in materials from north-central Siberia (Late Permian and Triassic) and Germany (Sakmarian to Anisian, up to the Jurassic).

Stability assessment of PITT tracer candidate compounds – The case of pyrazines

The determination of the residual oil saturation (SOR) in the volumes swept between injector/producer well pairs is a parameter of major importance for the design and/or evaluation of IOR projects. The number of IOR projects is increasing with the growing number of mature oilfields. The partitioning inter-well tracer test (PITT) is used to measure SOR in waterflooded reservoirs and relies on the use of partitioning and passive tracers. Many PITT were unsuccessful in the past due to a poor knowledge about the compounds used as tracers and to date, very few compounds were developed for this application. New partitioning tracers are needed, and a systematic qualification process is necessary to reduce the risk of costly unsuccessful field tests. In the present document we report and discuss the findings from stability experiments performed on 2 alkylpyrazines, 1 methoxypyrazine, and 2 halogenated pyrazines under investigation for use as oil/water partitioning tracers for determination of the SOR in the inter-well region of water flooded oil reservoirs.The stability of 2,3-dimethylpyrazine, 2,6-dimethylpyrazine, 2-methoxypyrazine, 2-chloropyrazine, and 2-fluoropyrazine in brine solutions was evaluated in batch experiments at temperatures ranging from 25 °C to 150 °C for 12 weeks, at 3 different pH values and in the presence of typical oil reservoir rock materials (sandstone, carbonate rock, and clay). Results suggest that 2,3-dimethylpyrazine and 2,6-dimethylpyrazine possess the required stability and absence of significant interaction with the rock substrates. 2-chloropyrazine and 2-fluoropyrazine degrade with a temperature and pH dependent rate but are not influenced by the rock materials. 2-methoxypyrazine exhibits temperature dependent degradation in the absence of any rock substrate and in the presence of sandstone and carbonate rock. A strong interaction was observed between this compound and the clay material (kaolinite) which is responsible for dramatically increasing its degradation rate.

Computing via natural erosion of sandstone

Logical gates are constructed based on a method of numerical modeling of natural erosion of sandstone. Values of logical variables are determined by the presence of sandstone. The presence of sandstone corresponds to the logical value of True, whereas the absence of material corresponds to the False value. Logical functions are computed through the formation of sandstone structures at action of natural erosion where loading conditions are specified. AND and XOR gates and a one-bit binary half-adder are implemented.

Adsorption of Aerosol-OT on Sand and Shale at High Sodium Salt Concentration

Surfactant flooding is a method for additional recovery of oil from partially depleted reservoirs by changing the interfacial tension. During the application of surfactant into a reservoir, a certain loss in the high equivalent weight fraction occurs. These surfactant molecules are the most efficient in lowering the interfacial tension between reservoir brine and crude oil. Introducing the surfactant to rock sediment may result in these losses and increase the partition or adsorption of hydrocarbon organic compounds (HOCs) in the rock-water system. The adsorptive behaviour of Aerosol-OT was studied under high salt concentration at room temperature in the presence of sandstone and shale. This study detected the adsorption based on the monitored changes in the initial concentration of the surfactant. The adsorption of the surfactant Aerosol-OT has been investigated using batch adsorption isotherms and the technique of UV-Vis spectroscopy. The objective of the study was to gain further insight into the surfactant adsorption for these adsorbents and to determine the appropriate isotherm model. The equilibrium results showed that the value of concentration changed from 0.03 g/L to the lowest value of 0.0124 g/L, which is lower than half. The batch adsorption isotherms that Aerosol-OT adsorption behaviour followed was found to fit Langmuir-Frandluich model.

Adsorption of sodium dodecyl sulfate, Triton X100 and their mixtures to shale and sandstone: A comparative study

In this paper, batch experiments of sediment/aqueous systems were conducted to evaluate the adsorption of SDS, TX100 and their mixtures (1:2; 1:1 and 2:1 SDS:TX100 mass ratio) onto local shale and sandstone. Adsorption of surfactants was assessed using a surface tension technique for surfactant concentrations less than surfactant monomer saturation (CMC). It is shown that the amount of TX100 adsorbed to shale (7.5 g/kg) are greater than those adsorbed to sandstone (1.5 g/kg). SDS showed negligible affinity for adsorption on both adsorbents. The amounts of both TX100 adsorbed to shale or sandstone can be decreased and minimized when they are mixed with SDS. While adsorption of TX100–SDS mixtures on shale reduced to 4.5 g/kg (40% reduction in comparison to adsorption of TX100), adsorption to sandstone decreased tremendously to 0.3 g/kg (80% reduction in comparison to adsorption of TX100). Furthermore, micellization behavior was assisted through mixing. CMCs of mixtures reduced to 0.1 wt.% in presence of shale compared to 0.15 wt.% for TX100 and 0.1 wt.% for SDS. Similarly, CMC of mixtures reduced to 0.03 wt.% in presence of sandstone in comparison to 0.05 for pure TX100 and 0.1 wt.% for SDS. Because of their ability to minimize amounts adsorbed in different adsorbents, mixed anionic–nonionic surfactant particularly TX100–SDS may show potential advantages in SEAR and EOR applications.

Rivisitazione geologica della grande Galleria dell’Appennino

Rivisitazione geologica della grande Galleria dell’Appennino

Polygonal Faults and Their Influence on Deep-Water Sandstone Reservoir Geometries, Alba Field, United Kingdom Central North Sea

Polygonal faults attributed to three-dimensional (3-D) volumetric contraction of muddy sediments during early burial are widespread within the Eocene-lower Miocene succession of the United Kingdom central North Sea. The analysis of a 3-D seismic survey encompassing the Eocene Alba field in the central North Sea has allowed us to investigate (1) the influence of polygonal faults in surrounding mudrocks on the geometry of the Alba deep-water sandstone reservoir and (2) how the presence of the reservoir sandstone influences the polygonal fault pattern above and below the reservoir. The main reservoir in the Alba field is an elongate (12 km long, 1-2 km wide, up to 90 m thick), fine-grained, massive sandstone body that may have been deposited in a deep-water channel or slope gully. Although depositional processes likely have been responsible for the dominantly linear sandstone distribution, the current reservoir geometry is largely controlled by the location of polygonal faults in the surrounding hemipelagic mudstones. Sandstones interpreted as injected along faulted margins of the Alba field indicate that faulting facilitated remobilization and sand injection during early burial, further modifying the reservoir shape. Unusual, isolated 1-km-wide subcircular mounds to the west of the main field also are attributed to sand withdrawal and remobilization during early burial. On a mapped marker horizon in the mudrocks 80-120 m above the reservoir there is a marked decrease in polygonal fault density compared to areas away from the reservoir. On a horizon in mudrocks within 5-50 m of the base of the reservoir there is an increase in horizon disruption due to small faults directly below the sand body. Changes in polygonal fault density and pattern thus may indicate the presence of sandstones and may be a useful exploration tool for explorationists searching for subtle Eocene deep-water sand bodies that typically are poorly imaged on seismic data in the North Sea.

青森県・深浦‐鯵ケ沢地域，前期中新世大戸瀬層のＫ‐Ａｒ年代と火山岩相

K-Ar dating was performed for volcanic rocks from the early Miocene Odose Formation, Fukaura-Ajigasawa area, Aomori Prefecture in northeast Japan to determine the age of the early Miocene transgression, prior to the Nishikurosawa transgression of these area, and to make clear an spatial distribution of marine sediments (>20 Ma) found in the Oga Peninsula, Akita Prefecture. The Odose Formation is divided into three members: the Kiyotakizawa Andesite, the Azumagawa Rhyolite and the Kohamadatezawa Andesite Members in ascending order in the Ajigasawa area (Hirayama and Uemura, 1985), which are corresponded to the lower, middle(Sawabe volcanic rock) and upper part in the Fukaura area (Moritani, 1968). Preliminary facies analysis of the Sawabe volcanic rock and the upper part of the Kiyotakizawa Andesite Member of the Odose Formation indicates that these volcanic sequences were deposited in the near shore environment, evidenced by the presence of sandstone with hammocky cross stratification and intrusion of spiracle into aa lava flows. A high alumina olivine pyroxene andesite of the Sawabe volcanic rock has an age of 20.0±1.0 Ma which coincide with the age of 20.6±2.0 Ma reported by Fukudome et al. (1990), and an alkali olivine basalt from the upper part of the Kiyotakizawa Andesite Member shows 19.4±1.1 Ma. Because marine molluscan fossils were found by Hirayama and Uemura (1985) from the middle part of the Kiyotakizawa Andesite Member, the age from the upper part of the member constrains the upper limit a marine sediment age by early Miocene transgression in Ajigasawa area. Furthermore, the result of the present K-Ar age study indicates that the marine sediments in the area are well correlate with the sediments in the Oga Peninsula.

Gravity anomalies associated with the Cefn‐y‐Fedw Sandstone Group, northeast Wales, and their geological significance

AbstractRegional and detailed gravity surveys over Carboniferous rocks in northeast Wales have revealed an elongated Bouguer anomaly low over part of the outcrop of the Cefn‐y‐Fedw Sandstone Group. The anomaly has a pronounced gradient over the boundary of these sediments with the limestones of the underlying Viséan Series, but downdip, to the east, the anomaly merges with the general decrease of Bouguer anomaly values. The anomaly can be explained if the thickness of the lower density Cefn‐y‐Fedw Sandstone Group increases abruptly along the margin of the outcrop of these rocks. Various explanations for this are considered including faulting, a syncline. and channel‐like deposits. The interpretation is further complicated by the presence of sandstones with densities varying between 2·2 Mg m−1 and 2·6 Mg m−3Although a full explanation is not possible without further evidence, the existence of the Bouguer anomaly low necessitates a review of the nature of the Cefn‐y‐Fedw Sandstone Group.

Lisburne Group (Mississippian and Pennsylvanian), Potential Major Hydrocarbon Objective of Arctic Slope, Alaska

The Lisburne Group, a thick carbonate-rock unit of Mississippian and Pennsylvanian age, is one of the most widespread potential reservoir-rock units in northern Alaska. A comprehensive review of the Lisburne in the subsurface of the eastern Arctic Slope indicates attractive reservoir characteristics in a favorable source and migration setting where numerous trapping mechanisms appear to be available. Evaluation of this group as a potential exploration objective is particularly timely because of impending offshore sales in the Beaufort Sea and current exploration programs under way in the Prudhoe Bay area and the Naval Petroleum Reserve. Dolomite and sandstone have been identified as reservoir rocks. Oolitic grainstone is a common rock type, but observations indicate little reservoir potential owing to complete void filling by calcite cement. The most important reservoir rock as judged by thickness, areal extent, and predictability is microsucrosic (10 to 30µ) dolomite of intertidal to supratidal origin. It is present throughout the Lisburne and is most abundant near the middle of the sequence. Northward it decreases in thickness from 1,000 ft (300 m) to less than 100 ft (30 m). Porosity of the dolomite as determined in selected wells averages between 10 and 15% and attains a maximum of slightly more than 25%. Net thickness of reservoir rocks (i.e., rocks with greater than 5% porosity) ranges in these wells from 40 to 390 ft (40 to 120 m). Oil shows are common, and drill-stem tests have yielded as much as 1,600 bbl/day of oil and 22 MMcf/day of gas in the Lisburne pool of the Prudhoe Bay field and as much as 2,057 bbl/day of salt water outside the field area. The occurrence of dolomite over such a large area makes its presence in the offshore Beaufort Sea and adjacent Naval Petroleum Reserve 4 fairly certain. The presence of sandstone as thick as 140 ft (40 m) in the middle and upper part of the Lisburne in two coastal wells suggests that larger areas of sandstone may be found on the north in offshore areas. Shows of oil and gas and a saltwater flow of 1,470 bbl/day have been recorded from this sandstone facies. Shales of Permian and Cretaceous ages unconformably overlie the Lisburne, providing adequate sealing beds above potential reservoirs. Impermeable limestone (completely cemented grainstone) and thin beds of shale may serve as seals within the Lisburne, but the possibility of fractures in these units may negate their sealing capability. The most favorable source rock for Lisburne hydrocarbons appears to be Cretaceous shale that unconformably overlies the Lisburne east of Prudhoe Bay. This shale is reported to be a rich source rock and is the most likely source for the entire Prudhoe Bay field. A source within the Lisburne or within the underlying Kayak Shale is postulated for oil shows in the southernmost Lisburne wells. This postulated source may be in a more basinal facies of the Lisburne and may be similar to dark shale in the upper Lisburne in thrust slices to dark shale in the upper Lisburne in thrust slices in the Brooks Range. Coal in the underlying Endicott Group is a possible source for dry gas. At present, much of this coal probably is in a gas-generating regime downdip from the Prudhoe Bay field. Stratigraphic traps involving the Lisburne Group may have resulted from widespread Permian and Cretaceous unconformities. Structural traps related to normal faulting may be present along the trend of the Barrow arch, and faulted anticlines are numerous in the foothills of the Brooks Range. Combination traps are possible along the trend of the Barrow arch.