Sandstone Formation Research Articles

A revised hydrogeological conceptual model of the Fell Sandstone aquifer, Northumberland and its impact on the interpretation of long-term nitrate trends

Northumbrian Water abstract groundwater from the Fell Sandstone Formation (part of the Carboniferous Border Group) in north Northumberland, which is a groundwater-only water resource zone providing drinking water to Berwick-upon-Tweed and the surrounding area. Groundwater in observation and abstraction boreholes shows significant rising nitrate levels derived from agricultural land use, and are predicted to have an impact on groundwater quality by 2030. Northumbrian Water policy is to use catchment management techniques to mitigate rising nitrate levels through influencing land-use practices and reducing nitrate concentration in groundwater recharge. This paper demonstrates how a detailed geological and hydrogeological understanding of the area has been used to identify specific areas where appropriate catchment management techniques may be most effectively applied. Northumbrian Water and the Environment Agency jointly funded the British Geological Survey to develop a numerical groundwater model of the Fell Sandstone aquifer and to undertake a review of the geology of the Fell Sandstone Formation as part of a Water Industry National Environment Programme (WINEP). Combining the results of these two studies, supported by spatial and temporal field measurements of groundwater nitrate levels, an improved understanding of the potential fate and transport of nitrate in the Fell Sandstone aquifer has emerged. This allows a better prediction of the spatial and temporal impacts of nitrate losses from the soil zone to the aquifer in support of a catchment management approach to mitigating rising nitrate levels. Thematic collection: This article is part of the Hydrogeology of Sandstone collection available at: https://www.lyellcollection.org/cc/hydrogeology-of-sandstone

Effect of water-soluble organic acids on wettability of sandstone formations using streaming zeta potential and NMR techniques: Implications for CO2 geo-sequestration

Rock wettability is influenced by several conditions, and one such factor is the potential at the rock/fluid interface. While most studies have reported zeta potential in this context, very few investigations have carried out streaming potential measurements. Further to this, most previous studies have only evaluated zeta potential/streaming potential for NaCl brine-clean sandstone systems, while it is clear that organic matter exists in subsurface rock. However, the effect of these forms of organic matter on streaming potential has not yet been probed. Accordingly, in this study streaming potential measurements were firstly conducted on pristine San Sabasandstonesamples with 0.3 mol.dm3 NaCl brine-saturated at (6.895 MPa overburden and 3.447 MPa back-pressure). Secondly, the streaming potential of the aged samples was measured under identical conditions (the cores were saturated with aqueous HA solutions of different concentration; 1–100 mg/L) in 0.3 mol.dm−3 NaCl. Thirdly, a comparative analysis of zeta potentials was conducted via electrophoretic and streaming potential. Lastly, the T2 spectrum for the initial water saturation of pristine and aged cores, along with the T2 spectrum of residual water saturation after CO2 flooding for pristine and aged cores, were measured with NMR core flooding measurements. Accordingly, this work analyses the effects of organic acids on wettability alteration in sandstone formation in accordance with these procedures. A strong correlation exists between surface adsorption of organic acid and streaming potential coefficient, where the amount of residual water saturation decreases in humic-acid aged cores – suggesting the presence of organic acid that changes wettability towards CO2 wet in pores, where the CO2 displaces more brine in aged cores compared to pristine cores.

Geotechnical Risk Assessment and Geological Origin of Building Fracturation in Agadez City (North Niger)

The Agadez city is built on the faulted and fractured sandstone formation of the “Agadez Sandstones”, which was deposited in unconformity on the Precambrian basement of the Aïr Mountain. The present study focuses on the geotechnical risk assessment and geological origin of building fracturation in Agadez city. A methodological approach integrating measurement of fractures planes affecting the buildings and their statistical analysis has been implemented. Statistical analysis of obtained data showed that in 100 fractured buildings, about 3% of buildings are at risk of collapse (very high risk), 64% of buildings are fractured (medium risk of collapse), and 34% of buildings are cracked (lower risk of collapse). These results showed as well that the nature of the material (rheology) influences the buildings fracturation. Indeed, buildings made from cement are more easily fractured than buildings made from clay materials. Statistical analysis of fracture planes reveals that the geotechnical risk associated with building's fracturation propagates in NW-SE, corresponding to the major directions of risk propagation, mainly dipping in northwest sectors (zones) of the Agadez city. The interpretation of geological and geophysical data combined with those obtained in the case of this study, reveals that the risk associated with buildings fracturation in Agadez city is caused by geological seismic events and or anthropogenic activities (explosive firing on the uranium mining sites like Somaïr and Cominak).

Integrating palynostratigraphy with zircon geochronology in the Lower Jurassic Precipice Sandstone and Evergreen Formation to improve stratigraphic correlation within the Great Artesian Basin, Australia

The Great Artesian Basin (GAB) in eastern Australia is one of the most productive complex aquifers on Earth, covering a large portion of the continent. Yet stratigraphic correlation within and among constituent basins of the GAB remain poorly constrained. This has significant implications for resource estimation and management. In this study and for the first time, palynostratigraphic and zircon geochronologic data are integrated from the Lower Jurassic Precipice Sandstone and Evergreen Formation in the Surat Basin–a component of the GAB. The goal was to better constrain the depositional ages as a starting point for calibrating stratigraphy across the GAB. The results showed that the Precipice Sandstone and Evergreen Formation are highly diachronous, as are their sequence stratigraphic subdivisions. We provisionally revise the stratigraphic framework based on the integration of age information to show that the “lower” Precipice Sandstone (lowstand systems tract) ranges from Hettangian to Pliensbachian, the “upper” Precipice Sandstone (transgressive systems tract) extends from Sinemurian to Pliensbachian, the Evergreen Formation varies from Pliensbachian to Aalenian within which the Boxvale Sandstone varies from Pliensbachian to Toarcian and the Westgrove Ironstone member ranges from Pliensbachian to Aalenian. Additionally, the data allow us to provisionally assign the APJ1 to APJ2 palynozone boundary to ∼190 Ma, the APJ3.2 to APJ3.3 boundary to ∼180 Ma, and to constrain the APJ2.2.2 palynozone to span 184.80 ± 0.20 Ma. This new age-context for the Precipice Sandstone and Evergreen Formation will be useful for future workers correlating strata between constituent basins of the GAB, as well as New Zealand and the broader Gondwana palaeocontinent.

Electrical, Diffusional, Hydraulic, and Geometrical Tortuosity Anisotropy Quantification Using 3D Computed Tomography Scan Image Data

Summary Sedimentary rocks display complex spatial distribution of both pore space and solid components, impacting the directional dependence of physical phenomena such as electrical conduction, fluid flow, heat transfer, and molecular diffusion. The complexity of the pore space is often quantified by the concept of tortuosity, which measures the sinuosity of the connecting paths in the pore space. Tortuosity is an important quantity in formation evaluation as it impacts petrophysical properties such as permeability and formation factor. However, the existence of various techniques can lead to nonuniqueness in assessment of tortuosity. Furthermore, spatial variation of the solid components of the rocks occurring at the core-scale domain reflected in the connectivity and distribution of the minerals is typically not quantified. The objectives of this paper are (a) to quantify tortuosity and tortuosity anisotropy of porous media through estimation of electrical, diffusional, hydraulic, and geometrical tortuosity at the pore scale and core scale and (b) to compare electrical, diffusional, hydraulic, and geometrical tortuosity. We estimate tortuosity in the pore space of microcomputed tomography (micro-CT) scan images and in the most connected and abundant solid phase of whole-core CT scan images. We conduct numerical simulations of electric potential distribution, diffusion, and fluid flow and velocity distribution to estimate electrical, diffusional, and hydraulic tortuosity, respectively. To calculate geometrical tortuosity, we use the segmented pore space from micro-CT scan images to extract a pore network model and compute the shortest path of all opposing pores of the samples. Finally, tortuosity values obtained with each technique are used to assess the anisotropy of the samples. We applied the documented workflow to core- and pore-scale images. The CT scan images in the core-scale domain belong to a siliciclastic formation. Micro-CT scan images in the pore-scale domain were obtained from Berea Sandstone, Austin Chalk, and Estaillades limestone formations. We observed differences in estimates of direction-dependent electrical, diffusional, hydraulic, and geometrical tortuosity for both types of images. The highest numerical differences were observed when comparing streamline electrical and hydraulic tortuosity with diffusional tortuosity. The observed differences were significant in anisotropic samples. Differences in tortuosity estimates can impact the outcomes of rock physics models for which tortuosity is an input. The documented comparison provides insight in the selection of techniques for tortuosity estimation. Use of core-scale image data provides semicontinuous estimates of tortuosity and tortuosity anisotropy, which are typically not attainable using pore-scale images. Additionally, the semicontinuous tortuosity anisotropy estimates from whole-core CT scan images provide a tool for selection of best locations to take core plugs.

Field test of radial jet drilling technology in a surface formation

The radial jet drilling (RJD) technology is an efficient formation stimulation and injection technology that drills multiple laterals perpendicular to the central well. Extensive research has been on jet rock breaking, lateral extension, productivity prediction, and technological processes. However, little public literature illustrates the overall drilling performance of the RJD systems. Herein, a field test is conducted in the surface sandstone formation. Eight laterals are successfully drilled using the self-rotating multi-orifices nozzle with a 35–40 MPa (5.08–5.80 ksi) jet pressure. The cumulative length of the eight laterals is 21.1 m (69.2 ft), with the longest one being 5.7 m (18.7 ft). The lateral diameter is 50 mm (1.97 in), drilled at the fastest drilling rate of 3.6 m/h (11.8 ft/h). The auxiliary traction device can provide extra feed-in force to the high-pressure hose. The lateral trajectories are measured with their accuracy confirmed by the coring well. During the field test, a lateral trajectory up-warping problem is found, of which the possible causes and the suggestions are provided. According to the internal shape of the lateral obtained by endoscopic imaging, the lateral section exhibits a ring structure, indicating the high rock breaking efficiency of the self-rotating multi-orifices nozzle. The formation anisotropy and natural fracture have little influence on the lateral trajectory but affect the lateral section shape. The research results prove the reliability of the RJD system developed and can contribute to future development and application of RJD technology.

Using multivariate adaptive regression splines to develop relationship between rock quality designation and permeability

The assessment of in situ permeability of rock mass is challenging for large-scale projects such as reservoirs created by dams, where water tightness issues are of prime importance. The in situ permeability is strongly related to the frequency and distribution of discontinuities in the rock mass and quantified by rock quality designation (RQD). This paper analyzes the data of hydraulic conductivity and discontinuities sampled at different depths during the borehole investigations in the limestone and sandstone formations for the construction of hydraulic structures in Oman. Cores recovered from boreholes provide RQD data, and in situ Lugeon tests elucidate the permeability. A modern technique of multivariate adaptive regression splines (MARS) assisted in correlating permeability and RQD along with the depth. In situ permeability shows a declining trend with increasing RQD, and the depth of investigation is within 50 m. This type of relationship can be developed based on detailed initial investigations at the site where the hydraulic conductivity of discontinuous rocks is required to be delineated. The relationship can approximate the permeability by only measuring the RQD in later investigations on the same site, thus saving the time and cost of the site investigations. The applicability of the relationship developed in this study to another location requires a lithological similarity of the rock mass that can be verified through preliminary investigation at the site.

Characteristics of fluid inclusions and fluid coupling mineralization of the Pengyang uranium deposit, Ordos Basin

The Pengyang uranium deposit, located in the Tianhuan Depression in the southwestern Ordos Basin, is a large-scale sandstone-type uranium deposit in aeolian sediments. The uranium-bearing rock series in the deposit is mainly sandstone and conglomerate from the Lower Cretaceous Luohe Formation, which is dominated by desert facies. Based on our investigation of the geological characteristics of this deposit, a systematic study of the type, characteristics of the ore-forming fluid and ore genesis was conducted. Through the petrographic study of inclusions, three stages of inclusions have been identified in the quartz overgrowth, carbonate cements, and secondary microfractures in the ore-bearing sandstone of the Luohe Formation, and the third-stage inclusions in the secondary microfractures or late calcite cements represent the ore-forming fluids. There are three types of inclusions captured from ore-forming fluids: liquid-dominated aqueous inclusions, liquid-dominated hydrocarbon inclusions, and natural gas inclusions. Their gaseous components are mainly CH4 and H2O, with a small amount of N2. The homogenization temperatures of liquid-dominated aqueous inclusions range from 58 to 147 ℃, and the salinity ranges from 0.35 to 6.88 wt%. The homogenization temperature of liquid-dominated hydrocarbon inclusions mainly exhibits two peaks (at 60–140 ℃ and 160–190 ℃). Our studies of carbon-hydrogen–oxygen isotopes indicate that the formation of uranium-bearing sandstone is closely related to the participation of organic matter such as oil and gas. Based on the comprehensive researches of fluid inclusions and isotope analysis, it is concluded that the ore-forming fluid of the Pengyang uranium deposit is a mixture of meteoric water and hydrocarbon fluid. The deep hydrocarbon fluid traveled upward along the structural fractures, acting as a reductive agent and participating in the oxidation–reduction reaction of the Pengyang uranium deposit. Although hydrocarbon fluid can bring some uranium from deep area, the uranium from the provenance area of the basin may be the main source of mineralization in the Pengyang uranium deposit. The Pengyang uranium deposit is a sandstone-type uranium deposit related to the reduction of oil and gas. Uranium mineralization is mainly caused by the coupling between the uranium-bearing oxygen-rich fluid infiltrated from the surface and the deep hydrocarbon fluid.

Dawsonite as a Temporary but Effective Sink for Geological Carbon Storage

The possibility of using dawsonite mineral trapping as a carbon capture and storage (CCS) strategy intrigues many. In this study, we used a dawsonite-rich (∼10%) CO 2 gas reservoir in the Hailar basin in northern China as a natural analogue of a CO 2 storage site, along with numerical modeling, to demonstrate that a large amount of dawsonite can be generated in sandstone formations, provided sufficient Na-rich feldspar and CO 2 gas are available. While precipitated dawsonite can be preserved only in a hydrodynamically-closed system in the long term under high CO 2 fugacity and log((Na + )/(H + )) activities in solution, short-term trapping of CO 2 in dawsonite (on the order of 10 kyr) is possible and lowers CO 2 pressure, which mitigates the risk of CO 2 leakage to the ground surface or overlying drinking water aquifers. The re-dissolution of dawsonite after a few thousand years facilitates progressive dissipation of the gas phase CO 2 over time. Consideration of reservoirs or saline aquifers with minerals or formation water that can provide a high abundance of dissolved sodium, significantly increases the number of potential CCS sites globally. Furthermore, alternating water-and-gas injection regimens could enhance the precipitation of dawsonite in Na-rich aquifers. Future editions of the Carbon Storage Atlas should consider aquifer geochemistry in the site selection for secure long-term carbon storage in addition to the volumetric considerations for short-term operation.

A High Effective Acid System to Stimulate Sandstone Reservoirs

Mud acid is regularly applied to recover or increase permeability of sandstone reservoir. However, due to its rapid reacting rate and heterogeneous displacement, the stimulation effect of conventional mud acid is relatively limited in sandstone formations. For mud acid, it is important to choose proper chemical additives to retard reaction rate and make it distributed homogenereously in formation. To overcome these shortcomings of mud acid, a new proprietary mud acid system has been developed for sandstone formations stimulation. The new system is composed of 2.0% multichemical solutions (MCS) +6.5%HCl+1.5% HF, and the combined solution contains nonionic surfactant, clay stabilizer, and dispersant which were specifically formulated. Core flooding experiments were conducted with the high effective mud acid; meanwhile, XRD and SEM analysis were performed before/after the core flooding tests. Retarded tests were also conducted for the new mud acid reacting with sandstone samples. Treatments with ten pores volume of the new high effective mud acid system were found to increase permeability of sandstone core approximately three times of its initial permeability. From the results of SEM and XRD analysis, most of clays were dissolved, and permeability was increased after core flooding by this new mud acid solution. On the basis of acidizing theory, the reaction retarded mechanism was explained about the new composite mud acid. Other properties of the new composite mud acid were also discussed. In comparison of conventional mud acid, the new composite mud acid can retard acidizing reaction rate and distribute evenly in formation; therefore, it can extend acidizing penetration and stimulate sandstone formation thoroughly. The new composite mud acid is more compatible and desirable than conventional mud acid, and it will be applied extensively for sandstone matrix stimulation.

Mitigating Water Production from High Viscosity Oil Wells in Unconsolidated Sandstone Formations

Summary Large reserves of high-viscous oil in Kuwait call for improved oil recovery scenarios. In Kuwaiti unconsolidated sandstone formations, the sandstone intervals represent extensive reservoir intervals of sand separated by laterally extensive nonreservoir intervals that comprise finer-grained argillaceous sands, silts, and muds. The reservoir is shallow with high permeability (above 1,000 md) and under bottom aquifer pressure support. Due to strong viscosity contrast between oil and water, after breakthrough, the water cut rises quickly, resulting in strong loss of production efficiency. Mitigating water production is thus mandatory to improve production conditions. The candidate wells have two to three open intervals in different rock facies with comingle production. The total perforated length is between 38 and 48 ft. Production is through progressing cavity pumps (PCP) at a rate of around 300 B/D, and basic sediment and water is between 71 and 87%. The technology applied utilizes pregelled size-controlled product [small microgels (SMG Microgels)] having relative permeability modification (RPM) properties; that is, inducing a strong drop of relative permeability to water without affecting oil relative permeability. The size is chosen to selectively treat the high-permeability water producing zones while preserving the lower-permeability oil zones. The chemical can also withstand downhole harsh conditions such as salinity of around 170,000 ppm and presence of 2% H2S. The treatment consisted of bullhead injection of 300 bbl of pregelled chemical through-tubing. The first results seem very favorable, since for two wells, the water cut has dropped from 80 to 40% with almost same gross production rate. The incremental oil is more than 100 BOPD. The third well did not show marked change after water system operation (WSO) treatment. The wells are under continuous monitoring to assess long-term performance. Such result, if confirmed, may lead to high possibilities for the improvement of heavy oil reservoir production under aquifer support by mitigating water production with simple chemical bullhead injection.

The Effect of Weighting Agents on Sandstone Formation Damage from Water-Based Drilling Fluids

Summary Chemical properties of a fluid used in oil and gas drilling operations are critical as they directly affect drilling performance and, most importantly, formation damage in production zones. The increased requirement for high-density fluids to maintain deeper, more complex well trajectories may translate to an increase in drilling fluid solids content when brine-weighted fluids are not compatible or readily available, as more weighting materials are added to increase density and control formation pressures. However, these weighting agents can also plug pores and cause formation damage, leading to significantly reduced productivity and the need for remediation. The objective of this study is twofold: To evaluate and compare solids invasion and damage characteristics and performance of different weighting materials in water-based reservoir drilling fluids (RDFs) and to study the solubility behavior of micronized ilmenite in different acid systems. Several fluid systems were prepared using weighting agents differing in size, morphology, and chemical nature, primarily American Petroleum Institute (API) barite, micronized barite, and micronized ilmenite. Rheological properties were measured and high-pressure/high-temperature (HP/HT) static filtration experiments were conducted to investigate filtration behavior and filter-cake thickness. A modified coreflood setup was used to simulate dynamic drilling conditions downhole and accurately measure the effect of solids on formation damage. Computed tomography (CT) scan analysis provided the extent of the damage associated with each weighting agent. Within the scope of the study and limits of the experimental setup, results showed that the formation damage created by micronized ilmenite is much lower, compared to API and micronized barite in Bandera, Berea, and Boise sandstones. HP/HT solubility reactions with different blends of acids were monitored. The best acid system was tested with a complete drilling fluid system using the mud loop to ensure the ability to remediate damage from drilling operations.

Eocene Sedimentary–Diagenetic Environment Analysis of the Pingtai Area of the Qaidam Basin

Based on the petrological characteristics and elemental geochemical analysis of core samples from the Pingtai area in the northern structural belt of the Qaidam Basin, this study shows that the clay mineral assemblage of Lulehe Formation sandstone is dominated by high contents of smectite, chlorite and illite, and does not contain illite–smectite mixed layers or kaolinite. The chlorite and illite in the Xiaganchaigou Formation decreased gradually and the smectite disappeared. In addition, illite–smectite mixed layers began to appear and kaolinite was not present. These results indicate that the diagenetic environment of the Pingtai area in the early Eocene was dominated by alkaline media poor in K+ and rich in Mg2+, Na+ and Ca2+. In the late Eocene, K+ content in the diagenetic medium increased significantly, and smectite began to transform into illite. From the early Eocene to the late Eocene, the overall climate and environmental characteristics showed a transition from cold and dry to a cold climate that alternated between dry and wet. The content changes of common oxides, such as CaO, MgO, K2O, Na2O, SiO2, Al2O3, Fe2O3 and TiO2, showed obvious correlation. Based on the content and ratio change tendencies of Sr, Ba, Cu, Zn, U, Th, Ce and other trace elements, combined with the variation characteristics of rare earth element contents, it is suggested that the Lulehe Formation was dominated by a dry and cold freshwater sedimentary environment, and that paleoclimatic conditions were relatively cold and arid during this sedimentary period. However, the climate in the sedimentary period of the Xiaganchaigou Formation was dominated by a cold environment alternating between dry and wet, which also reflected the finding that the global climate was mainly cold and dry in the early Eocene and gradually became warm and humid in the late Eocene.

Grain size analysis of the Renji Formation (Barail) and Bhuban Formation (Surma) sandstones in the Barak basin, Manipur, India: Implication for nature of transport and depositional environment

The grain-size analysis in the sandstones of the Renji Formation (Barail Group) and Bhuban Formation (Surma Group) in parts of the Barak Basin, western Manipur, India was carried to determine the grain size distributions, modes of sediment transportation and depositional environment. The grain size of the Barail sandstone ranges from 2.3ɸ to 3ɸ and their grains show well sorted to moderately well sorted, symmetrical to coarse - skewed as well as nearly very fine – skewed and mesokurtic nature whereas the grain size of the Surma sandstone varies from 2.7ɸ to 3.4ɸand these grainsdisplay moderately well sorted to moderately sorted, coarse - and symmetrical skewed, mesokurtic to very leptokurtic nature. The Kurtosis analysis shows that the Barail siliciclastic sediments have been sorted in normal energy condition, whereas the Surma siliciclastic sediments likely have been sorted in normal to low as well as high energy conditions. Generally, the Barail and Surma sandstones show unimodal distribution. A shallow marine environment has been envisaged for the deposition of sediments of both the Barail and the Surma sandstone, dominated by saltation process.

Characteristics of Source Rocks and Formation of Reservoir Bitumen in Yinchuan Graben, Ordos Basin, China

The Yinchuan Graben is an important potential exploration area that is located on the western margin of the Ordos Basin. Over 8000 m of Cenozoic strata have been formed since the Cretaceous. With an integrated approach of cores observation, logging analysis, and geochemical analysis, we analyzed the characteristics of the Cenozoic source rocks in the Yinchuan Graben and determined the formation and destruction of the fossil oil reservoirs. With type III kerogen, the TOC of the dark mudstone in the Qingshuiying Formation is up to 7.5%, and the Ro is 0.95–1.04%, indicating the source rocks have entered the mature stage but the hydrocarbon generation potential is insufficient. A quantity of reservoir bitumen and oil-bearing fluid inclusions (GOI = 1.67–4%) were found in the Qingshuiying Formation sandstone in Well YQ-1, which indicates a fossil oil reservoir had existed. The fossil oil reservoir and reservoir bitumen were generated by the unexplored pre-Cenozoic strata in the Yinchuan Graben. The reservoir bitumen has high maturity and is associated with many fluid inclusions with a high homogenization temperature or CO2. This indicates that the bitumen was formed by the pyrolysis of the oil which was caused by the hot fluid migrating along with the deep fault belts.

Effect of supercritical CO2 on limestone's pore structure based on NMR and SEM

Supercritical CO2 (SC-CO2), as a new type of energizing fluid, has been widely applied in fracturing and acidizing treatment on tight sandstone, shale and carbonate formation. However, the effect of SC-CO2 on limestone's pore structure is unclear. To explore the effect, SC-CO2 reactor featuring high-temperature and high-pressure was used to carry out soaking experiments of SC-CO2-brine-limestone and SC-CO2-limestone respectively. With the help of NMR and SEM, this paper studies the effect of SC-CO2 on limestone's pore structure when the soaking time is different. It is found that in the experiment of SC-CO2-brine-limestone, SC-CO2 will react with brine to produce carbonic acid, which would react with calcite to augment limestone's porosity and permeability. Yet at the same time, Ca2+ and Mg2+ in the brine deposit continuously, which would lessen limestone's porosity and permeability. Besides, it is the generation of large pores that leads to augmentation of porosity, and more large pores are produced as time increases. While in the experiment of SC-CO2-limestone, volume expansion caused by transforming SC-CO2 into gaseous CO2 also augments limestone's porosity, and the augmentation is due to small pores. However, the increase of porosity in experiments without brine is much lower than that with brine.

Connectivity and permeability of Zhuhai tight sandstone heterogeneous reservoirs from western Pearl River Mouth Basin (China) by nuclear magnetic resonance

Resolving pore attributes and connectivity of oil-bearing sandstone formations is key to the precise estimation of the oil storage and flowing capacity of the reservoirs. However, very few studies have quantitatively characterized the individual porosities of interconnected pores and inaccessible pores. This study addresses these research gaps by studying Zhuhai sandstone from the western Pearl River Mouth Basin, China, with very low to medium permeability (0.055–346 mD). Nuclear magnetic resonance (NMR) centrifugation distinguished the interconnected and inaccessible pores. NMR T2 parameters (T2 cutoff and T2g) had a distinct impact on the connectivity index and irreducible water saturation. This study successfully developed an adaptable model that can efficiently estimate permeability in heterogeneous porous media, where no samples are taken, using NMR log. The permeabilities calculated by Schlumberger Doll Research, Coates-cutoff, Coates-BVI, and SDR-reg models were compared with those measured using a gas permeameter. Permeabilities were best calculated using flow-accessible porosity (i.e., Coates-BVI model, 95% matching) rather than other models. The connectivity (0.13–0.84) and movable fluid porosity (1.46–19.32%) were the primary factors that control permeability, and the fracture/crack attributes determined dual porosity. The study revealed that illite in clay minerals exerts a positive control on permeability by sheltering the interconnected primary porosity.

Surface water quality and geogenic process in the quillcayhuanca and shallap streams, huaraz-Peru

This research developed because, given the evidence of previous studies, it is necessary to determine the chemical quality of the water in the Quillcayhuanca and Shallap streams, which surround the city of Huaraz on its way to the Santa River, on the western slope of the Cordillera Blanca in Peru. In this sense, the investigated area is located at altitudes between 3524 m.a.s.l. and 4174 m.a.s.l. Twenty-four surface water samples were collected and analyzed for anions, metal, and total cations at the INGEMMET laboratory, Geological, Mining, and Metallurgical Institute of Peru. Likewise, geological mapping was carried out to identify the mineralized and chemically altered areas, evidencing the significant presence of sulfides (pyrite). The waters of the streams have been characterized as magnesium calcium sulfate, with SO4= anion contents of up to 181.10 mg/L in the Quillcayhuanca stream and 78.8 mg/L in the Shallap stream. Likewise, for both streams, an oxidized acid environment has been determined. The oldest stratigraphic unit corresponds to shales and sandstones of the Upper Jurassic Chicama Formation. The igneous rocks are made up mostly of granodiorites and tonalites corresponding to the Batholith of the Cordillera Blanca from the Neogene-Miocene. The Quaternary is represented by glacial, glacial fluvial, morainic and fluvial deposits. Regarding the chemical quality of the water, some elements exceed the environmental quality standards (ECA) for "Surface water intended for the production of drinking water" such as Al, Fe, and Mn. These elements are due to geogenic factors, given the presence of sulfides in the exposed rocks in the upper parts of the ravine plus the alteration of aluminosilicates in the exposed rocks.

Numerical investigation of sand production mechanisms in weak sandstone formations with various reservoir fluids

A three-dimensional CFD-DEM simulation method was developed to investigate the influence of different reservoir fluids on sand production. The fluid properties and reservoirs were prescribed and modelled after the conditions in the Kenkiyak and Uzen oil fields in Kazakhstan. A cylindrical sandstone sample was modelled using the Discrete Element Method in three stages of the pluviation, diagenesis, and perforation processes as in the oil field. A coupled simulation with the Computational Fluid Dynamics was used to simulate the sand production from the perforated sandstone under different fluid flow conditions with light and heavy oils. A continuous sand production was found to be more severe with the heavy oil flow due to its higher transport capability and a microstructural sanding mechanism that mobilized a higher proportion of the sample's particles with the fluid outflow. Sand production for light oil occurred in two stages of a first transient sand production that was followed by a second continuous sand production. The transient sand production was associated with more significant bond breakage, particle movement and porosity change within the damage zone that was created by the central perforation inside the sandstone sample.

Effect of temperature on sandstone acidizing using non-Newtonian fluids

Rock formation is subjected to acid stimulation to increase oil reservoirs productivity. Acidizing of sandstone rocks is a common method to remove damage and recover the oil flow to the wellbore. A matrix acid stimulation will always require additives depending on mud acid (HF/HCl) components, which cause non-Newtonian fluid behavior. In this study, the 3-D mathematical model of sandstone matrix acidizing in radial flow has been presented by a modified two-parameter model to consider non-Newtonian fluids and temperature effects. To this end, the Carreau-Yasuda equation has been employed to predict dissolution patterns created by non-Newtonian reactive fluids in sandstone formations. Meanwhile, the energy equation has been solved in the porous media to estimate the temperature in each time step, which affects the dissolution patterns in matrix acidizing. Three main phenomena are involved in dissolution patterns: surface reaction, diffusion and convection. Acidizing simulation indicates the acid-rock reaction constant in the formation network is temperature sensitive, and increases exponentially by increasing the reservoir temperature. In this work, the effects of various heterogeneity magnitude and porosity in the porous media, injection rate, reaction rate constant, power-law index (n) and temperature are considered by the various presented dissolution patterns of sandstone acidizing. The results show that, to reach a certain penetration length, the pore volume (PV) of injected acid decreases sharply with reservoir temperature, but after the critical temperature, it decreases slowly. The model discretized the Darcy, mass and energy balance equations by finite difference method and pore evaluation by Karman-Cozney correlations, and then employed the Tri-Diagonal matrix algorithm (TDMA) method to achieve the solution of the model and analysis of dissolution patterns in various acidizing regimes and rheological properties. All mathematical estimations including Darcy correlations, mass and energy balance and pore evaluation have been solved in FORTRAN program by parallel processing to accelerate 3-D calculations.