Sand Pack Research Articles

From loose sand to sandstone: An experimental approach on early calcite precipitation in sands of siliciclastic and mixed carbonate-siliciclastic composition.

Artificially cemented sandstones were produced to assess the impact of detrital texture and composition on the precipitation and distribution of early calcite cement, and cement-related degradation in porosity. To simulate early-calcite cementation, loose sediment of variable composition (siliciclastic and calcareous) and grain size was exposed to a calcite supersaturated solution for 35 to 58 days at 23°C. Identification and distribution of the newly precipitated crystals was performed with high resolution 2D optical and scanning electron microscopy. The experimental results show the precipitation of grain-coating, pore-bridging and pore-filling granular calcite cement with up to 100 μm crystal size. Despite a positive correlation between the amount of detrital carbonate grains and calcite crystals, calcite cement does not preferentially nucleate on bioclast surfaces, irrespectively of their favourable mineralogy. Siliciclastic grains show high calcite cement coverage with altered feldspar, particularly plagioclase, displaying coverage of 94.3%. Grain size variations within the sand packs have influence on the precipitation pattern of calcite with coarse-grained layers (500-710 μm) showing minor calcite cementation (6.3%), while medium- (250-500 μm) to fine-grained layers (125-250 μm) comprise average calcite cement contents of 16.3% and 28.2%, respectively. The findings of this study enhance our knowledge regarding the precipitation processes of calcite in porous material with heterogeneous reacting mineral phases, shapes and pore connectivity.

Laboratory measurements of water saturation effects on the acoustic velocity and attenuation of sand packs in the 1–20 kHz frequency range

AbstractWe present novel experimental measurements of acoustic velocity and attenuation in unconsolidated sand with water saturation within the sonic (well‐log analogue) frequency range of 1–20 kHz. The measurements were conducted on jacketed sand packs with 0.5‐m length and 0.069‐m diameter using a bespoke acoustic pulse tube (a water‐filled, stainless steel, thick‐walled tube) under 10 MPa of hydrostatic confining pressure and 0.1 MPa of atmospheric pore pressure. We assess the fluid distribution effect on our measurements through an effective medium rock physics model, using uniform and patchy saturation approaches. Our velocity and attenuation (Q−1) are accurate to ±2.4% and ±5.8%, respectively, based on comparisons with a theoretical transmission coefficient model. Velocity decreases with increasing water saturation up to ∼75% and then increases up to the maximum saturation. The velocity profiles across all four samples show similar values with small differences observed around 70%–90% water saturation, then converging again at maximum saturation. In contrast, the attenuation increases at low saturation, followed by a slight decrease towards maximum saturation. Velocity increases with frequency across all samples, which contrasts with the complex frequency‐dependent pattern of attenuation. These results provide valuable insights into understanding elastic wave measurements over a broad frequency spectrum, particularly in the sonic range.

Preparation and Characterization of Preformed Polyelectrolyte and Polyampholyte Gel Particles for Plugging of High-Permeability Porous Media.

Excessive reservoir water poses significant challenges in the oil and gas industry by diminishing hydrocarbon recovery efficiency and generating environmental and economic complications. Conventional polymer flooding techniques, although beneficial, often prove inadequate under conditions of elevated temperature and salinity, highlighting the need for more resilient materials. In this research, two types of acrylamide-based preformed particle gels (PPGs) were synthesized, as follows: polyelectrolyte and polyampholyte. These PPGs were engineered to improve plugging efficiency and endure extreme reservoir environments. The polyelectrolyte gels were synthesized using acrylamide (AAm) and sodium acrylate (SA), while the polyampholyte gels incorporated AAm, AMPS, and APTAC, with crosslinking achieved through MBAA. The swelling properties, modulated by temperature, salinity, and pH, were evaluated using the Ritger-Peppas and Yavari-Azizian models. The mechanical characteristics and surface morphology of the gels were analyzed using SEM and BET techniques. In sand pack experiments designed to mimic high-permeability reservoirs, the inclusion of 0.5 wt.% of fine PPGs substantially reduced water permeability, outperforming traditional hydrogels. Notably, the polyampholyte PPGs demonstrated superior resilience and efficacy in plugging. However, the experiments were limited by the low test temperature (25 °C) and brine salinity (26.6 g/L). Future investigations will aim to apply these PPGs in high-temperature, fractured carbonate reservoirs.

A pore-scale lattice Boltzmann model for solute transport coupled with heterogeneous surface reactions and mineral dissolution

In this paper, we propose a pore-scale lattice Boltzmann model to simulate fluid flow coupled with heterogeneous surface reactions and mineral dissolution. The primary innovation lies in the transformation of surface reactions, originally treated as a boundary condition, into a volume-source term through dimensional augmentation within the framework of sharp liquid–solid interfaces. This significantly simplifies the implementation, particularly for reactions occurring in porous media with intricate geometric structures. Several benchmark tests were performed to validate the accuracy of this model, including a reaction–diffusion problem in a rectangular domain, a two-dimensional reaction and dissolution of a circular grain, as well as a three-dimensional calcite crystal dissolution in a micro-channel. All the obtained simulation results agree well with the reference solutions. In addition, a dissolution problem in a three-dimensional porous medium built with the sand pack is then investigated. Cases with different Péclet numbers (Pe) and Damköhler numbers (Da) were simulated, and five dissolution modes were obtained, which were finally summarized in a diagram of Pe and Da.

Flow Behavior and Mechanism Insights into Nanoparticle-Surfactant-Stabilized Nitrogen Foam for Enhanced Oil Recovery in the Mature Waterflooding Reservoir.

To solve the problem of poor stability and low enhanced oil recovery efficiency of conventional foam, nanoparticle-surfactant-stabilized nitrogen foam was prepared, and the influence of temperature, salinity, oil content, and pressure on foam performance was systematically investigated. Then, the flow behavior of conventional foam and nanoparticle-surfactant-stabilized foam in porous media was studied. Parallel sand pack flooding and visualization microflooding experiments were performed to investigate the enhanced oil recovery ability of nanoparticle-surfactant-stabilized foam from core-scale to pore-scale. Results showed that the nanoparticles can improve foam performance. When the temperature increases from 60 to 100 °C, the foam volume and foam half-life of nanoparticle-surfactant-stabilized foam decrease by 20 and 36%, respectively. The nanoparticle-surfactant-stabilized foam has a good salt resistance. The oil content limit value of the foam performance is 15%. With the increase of pressure, the foaming performance and foam stability are enhanced obviously. Compared with conventional surfactant-stabilized foam, the nanoparticle-surfactant-stabilized foam can have better plugging and expansion of the swept volume capacity. The micromodel flooding results are consistent with the parallel sand pack flooding results. Compared with conventional surfactant stabilized foam, nanoparticle-surfactant-stabilized foam has better enhanced oil recovery ability than conventional surfactant-stabilized foam due to its higher foaming ability, foam stability, and sweep efficiency improvement ability.

Enhanced oil recovery and mitigating challenges in sandstone oil reservoirs employing EDTA chelating agent/ seawater flooding

While low salinity water (LSW) holds promise for improving oil recovery, its implementation is comparatively costly due to the substantial volumes of fresh water required to dilute seawater (SW). Additionally, concerns arise regarding potential issues related to LSW, including fines migration in sandstone reservoirs and scale formation in carbonate reservoirs. Chelating agents can be introduced into undiluted SW to bind with metal ions, thereby lowering its salinity. This approach mimics the behavior of LSW injection while overcoming associated challenges. This study involves measuring oil/injected solution interfacial tension (IFT), evaluating sandstone surface wettability alteration, along with conducting different sand pack flooding scenarios using Ethylenediaminetetraacetic acid (EDTA) chelating agent. The aim was to comprehend the EDTA oil recovery mechanisms and determine the optimal concentration of EDTA that minimizes chemical consumption while maximizing oil recovery. The findings indicated that incorporating 5 wt% EDTA into SW significantly reduced IFT from 29.52 mN/m to 4.75 mN/m, making the oil nearly miscible in the solution. Moreover, wettability tests confirmed that a minimum EDTA concentration of 5 wt% is required to shift wettability from oil-wet to strongly water-wet conditions. Sand pack flooding experiments, on the other hand, further demonstrated that this optimized fluid system can potentially recover an additional 16.1 % of oil following SW flooding. Finally, inductively coupled plasma (ICP) analysis revealed a notable increase in metal ion concentration during EDTA flooding, indicating enhanced leaching of metals from the sandstone surface and improved wettability characteristics.

Optimization on self-assembled ultra-micro foam system for carbon dioxide flooding

Given the problem that the conventional foam injection and salt resistance are poor, the oil displacement effect is not obvious, and it is difficult to enhance oil recovery in the ultra-low permeability and high salinity reservoirs of Yanchang Oilfield, it is imperative to study a new foam flooding agent. Based on the surfactant’s self-assembled properties, foaming agent, stabilizer and complexing agent were screened in the absence of polymer and non-alkali. Three sets of self-assembly worm-like micelle systems were screened, and then a set of carbon dioxide foaming system was selected through comparative analysis: 0.50 wt% EAPMAC-12 + 0.20 wt% SDS + 0.09 wt% TEOA + 0.08 wt% EDTA. Under this condition, its viscosity, foaming volume, foam half-life and foam composite index are 18.8 mpa·s, 531 mL, 25 min and 9956 mL·min, respectively. Under the condition of the ratio of gas to liquid 3:1, the ultra-micro foam was obtained by gas–liquid co-injection in the sand pack, and the foam was round rather than the traditional pentagonal or hexagonal shape and the size was 5–31 um, indicating that the foam had good injection. Oil displacement experiment showed the average enhanced recovery rate was 12.84 % in ultra-low permeability cores, indicating that the foam had good oil displacement effect in ultra-low permeability reservoirs.

Insights into the Injectivity and Propagation Behavior of Preformed Particle Gel (PPG) in a Low-Medium-Permeability Reservoir.

Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low-medium-permeability reservoir porous media is crucial for HPCF treatment in a low-medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low-medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55-72 and β is 3.4-6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding.

Appropriate characterization of reservoir properties and investigation of their effect on microbial enhanced oil recovery through simulated laboratory studies

Appropriate characterization of reservoir properties and investigation of the effect of these properties on microbial metabolism and oil recovery under simulated reservoir conditions can aid in development of a sustainable microbial enhanced oil recovery (MEOR) process. Our present study has unveiled the promising potential of the hyperthermophilic archaeon, identified as Thermococcus petroboostus sp. nov. 101C5, to positively influence the microenvironment within simulated oil reservoirs, by producing significant amounts of metabolites, such as biosurfactants, biopolymers, biomass, acids, solvents, gases. These MEOR desired metabolites were found to cause a series of desirable changes in the physicochemical properties of crude oil and reservoir rocks, thereby enhancing oil recovery. Furthermore, our study demonstrated that the microbial activity of 101C5 led to the mobilization of crude oil, consequently resulting in enhanced production rates and increased efficiency in simulated sand pack trials. 101C5 exhibited considerable potential as a versatile microorganism for MEOR applications across diverse reservoir conditions, mediating significant light as well as heavy oil recovery from Berea/carbonaceous nature of rock bearing intergranular/vugular/fracture porosity at extreme reservoir conditions characterized by high temperature (80–101 °C) and high pressure (700–1300 psi). Core flood study, which truly mimicked the reservoir conditions demonstrated 29.5% incremental oil recovery by 101C5 action from Berea sandstone at 900 psi and 96 °C, underscoring the potential of strain 101C5 for application in the depleted high temperature oil wells.

Introducing a novel method for determining the effective thermal conductivity at moderate and high Péclet numbers

AbstractFlow and heat transfer in porous materials is a common topic throughout many fields, including environmental and petroleum engineering. Using a coupled approach of experimental and simulation methods, this study presents a novel method for calculating thermal conductivity. Specifically, a new approach for the measurement of thermal dispersivity with both conduction and forced convection drives is proposed. In our experiments, temperature was monitored at different points within the porous medium, providing detailed spatial temperature distributions. These measurements allowed us to calculate and report effective thermal conductivity, enhancing the accuracy of our model. Experiments with various injection rates and temperatures were conducted on a sand pack. There is a relationship between the composition and connectivity of the solid in the geometry and heat transfer. However, in the case of forced convection, the key factor is the Péclet number which is important for optimal extraction of the heat inside the geothermal reservoir according to the cooling rate. When the Péclet number is high, the permeability of the porous medium plays a significant role. The velocity of the fluid can change the effective thermal conductivity up to four orders of magnitude. Due to the thermal resistance of solid and fluid, the temperature gradient between the boundary and the centre of the geometry was seen and temperature peaks were observed in the initial stages of the experiments. The size and number of peaks at the initial stage of the experiments are highly dependent on the matrix properties, such as thermal conductivity and surface area.

Effect of gravel pack permeability on horizontal well productivity loss under secondary methane hydrate formation: Experimental optimization of 3D randomly distributed mixed sand pack

Horizontal well productivity is limited by secondary hydrate formation (temperature drop results from endothermic of hydrate dissociation) during production. Seepage capacity as one of the key indexes for evaluating production efficiency, and efficiency is declined by sand production. Sand control is achieved by using gravel pack technology (selected sands for hindering the sediments particles migration), which extends the production time. However, forecasting the productivity decline trend from quantifying the permeability of the gravel pack after secondary formation remain challenges. To address these issues, a randomly distributed 3D normalized permeability (Kr) model was developed to describe the seepage capacity of gravel pack composed by various particle sizes of mixed glass beads. The theoretical modelling was established by observing micro spatial structure of glass beads with hydrate formation. The new model considered three consolidation modes of hydrate in pores (cementing + bearing, pore filling, and grain coating) and linked them with the productivity ratio equation of a horizontal gas well. To confirm the viability of the model, a series of permeability measurement experiments with various size ratios (α) from 1 to 10 were conducted. Finally, errors comparison and all parameters of the model were analyzed. The results showed that the productivity ratio declined clearly after saturation is >0.79, when α = 4. For long-term production, α = 10 would be better. The new model can help hydrate horizontal wells increase production from laboratory to industrial exploitation. KeyPoints•Secondary hydrate formation permeability model in gravel pack was established.•After secondary saturation's effect on horizontal well production was developed.•Gravel pack was simulated by random non-coincident particles with varies size ratios.•When the size ratio is 4, productivity ratio of horizontal well was extended.

Study on the Interaction of Interfacial Tension Between Water and Oil Surfaces In The Presence of Aluminium Coated With Polyvinylpyrrolidone (PVP) Nanoparticles

Applications of nanotechnology are frequently used in the oil and gas sector. However, nanoparticles boost sand consolidation, lower interfacial tension between water and oil, and improve the mobility of trapped oil to increase crude oil recovery in enhanced petroleum recovery (EOR). Using aluminium PVP-coated low-porosity sand packing, the effects of nanoparticles on interfacial tension and water-oil surface contact were examined in this study. The horizontal column was filled with low-porosity sand, and the nanopowders were suspended in deionized water. The four distinct nanoparticle suspension pore volumes (PV) used in this experiment are 0.25, 0.5, 0.75, and 1.0 PV. At the column's output, the sample is then deposited, and the effluent is analysed and contrasted using IFT and viscosity with a solid viscometer. In this investigation, it was discovered that the water target zone had a very limited pore volume and only received 0.52 PV of injected nanoparticles. The better the oil can be extracted, the lower the viscosity and IFT value. The removal of the oil droplet and increased oil output for EOR could result from the transport of PVP nanoparticles coated with aluminium.

Evolution of pore structure during fines migration in sand pack: NMR experimental and numerical investigations

Evolution of pore structure during fines migration in sand pack: NMR experimental and numerical investigations

Production, characterization, and application of Pseudoxanthomonas taiwanensis biosurfactant: a green chemical for microbial enhanced oil recovery (MEOR)

Biosurfactants, as microbial bioproducts, have significant potential in the field of microbial enhanced oil recovery (MEOR). Biosurfactants are microbial bioproducts with the potential to reduce the interfacial tension (IFT) between crude oil and water, thus enhancing oil recovery. This study aims to investigate the production and characterization of biosurfactants and evaluate their effectiveness in increasing oil recovery. Pseudoxanthomonas taiwanensis was cultured on SMSS medium to produce biosurfactants. Crude oil was found to be the most effective carbon source for biosurfactant production. The biosurfactants exhibited comparable activity to sodium dodecyl sulfate (SDS) at a concentration of 400 ppm in reducing IFT. It was characterized as glycolipids, showing stability in emulsions at high temperatures (up to 120 °C), pH levels ranging from 3 to 9, and NaCl concentrations up to 10% (w/v). Response surface methodology revealed the optimized conditions for the most stable biosurfactants (pH 7, temperature of 40 °C, and salinity of 2%), resulting in an EI24 value of 64.45%. Experimental evaluations included sand pack column and core flooding studies, which demonstrated additional oil recovery of 36.04% and 12.92%, respectively. These results indicate the potential application of P. taiwanensis biosurfactants as sustainable and environmentally friendly approaches to enhance oil recovery in MEOR processes.

Optimization of oil recovery using heated low salinity water (HLSW) in the horizontal sand pack column during water flooding: radiotracer intervention

Water-flooding is a prevalent technique for secondary oil recovery that is capable to increase oil recovery by up to 45%. Due to its accessibility, affordability, and simplicity, water flooding is the most frequently used secondary oil recovery technique. However, the efficiency of conventional water flooding is limited by capillary forces which holds the residual crude oil in pore structures. Moreover, during water flooding operation, the injected fluid does not penetrate sufficiently due to low permeability or presence of channelling inside the sandstone reservoir. Therefore, in this study, thermal recovery was introduced to 100ppm (0.1g/L) low salinity water (LSW) in order to investigate the percentage of oil recovery during water flooding. A horizontal sand pack column was used for water flooding experiment and temperature and injections rate are the parameters to be optimised with respect to percentage of oil recovery. The column was initially packed with 125micrometer sieved sand to ensure constant homogeneity is achieved. Initially, formation water which comprised with NaCl, CaCl2 and MgSO4 was introduced inside the column together with light oil and was aged overnight. TAPIS oil with viscosity of 0.001382 Pa.s (1.382cP) was used as light-oil in this study. The injection rate was set to 1 mL/min, 2 mL/min, and 3 mL/min respectively whereas, the temperature of the LSW was heated at 50 °C, 70 °C, and 90 °C subsequently. Heated water was supplied continuously throughout the sand pack which was heated using water blanket to retain heat at 70°C (reservoir temperature). In conclusion, 3 mL/min and 70°C were identified as optimum parameters and the oil recovery experiment was proceeded with liquid radiotracer using Technecium-99m (Tc-99m) intervention and resulted with 73% of yield. Nevertheless, the radiotracer intervention only provides the Residence Time Distribution (RTD) model which describe the behaviour of the sand pack during water flooding process.

Effect of sand gradations on the fresh properties of 3D printable concrete

Sand is frequently used as a fine aggregate in concrete mixtures, but the performance of concrete can be considerably impacted by regional variations in sand gradation. In this work, the effect of sand gradations on the fresh properties of three-dimensionally printable concrete (3DPC) mixtures was systematically investigated. The binder combinations (cement, fly ash, silica fume, limestone powder, ground granulated blast-furnace slag) and the water/binder ratio were kept constant throughout the trials. The sands used in the mixtures were standard Ennore sand (ES) (grades I, II and III) and locally available river sand (RS). The mini-slump heights and flow values of mixes made with RS and with optimal packing of binary and ternary combinations of the standard ESs were evaluated and compared with those of the unary packing of ESs and RS. A correlation between the fineness modulus of different sand gradations and printable flow time was determined. The influence of sand gradations and fineness modulus on buildability, shape retention, open time and extrudability were evaluated. It was found that the performance of the fresh 3DPC was influenced by the aggregate's gradation and grain size in addition to its fineness. In conclusion, different fine aggregate specifications must be chosen depending on the various 3D printing building conditions and design requirements.

Numerical modeling of the fracturing mechanisms of unconsolidated sand reservoirs under water injection

Produced Water Re-Injection is a standard practice in oil and gas operations. When performed at sufficiently high pressures, it can trigger the fracturing of the reservoir, which should be controlled to stimulate the formation without compromising its safety. While the mechanisms of the hydraulic fracturing of brittle rocks are well-understood, this understanding is more challenging in the case of unconsolidated sand reservoirs. Recent experimental studies indicate that pseudofractures in such formations primarily result from shear banding and flow channelization. There is a need for further interpretation of the experimental findings through numerical models that account for the proper physical phenomena. For that, a coupled finite element model of water percolation, particle transport and strain localization is developed to replicate the experiments of radial injection of water in mixtures of sand and fines by Nguyen et al., 2022: An experimental setup with radial injection cell for investigation of fracturing in unconsolidated sand reservoirs under fluid injection. Journal of Petroleum Science and Engineering 213:11036. To simulate shear banding, the model accounts for strain-softening behavior and introduces material imperfections in a few weak elements. Particle mobilization starts once a critical fluid velocity is reached and permeability is assumed to be a function of particle concentration. The numerical models can replicate the geometry of the observed radial pseudofractures, as well as the measured fracturing pressures. They also qualitatively capture the effects of the initial stress state on the fracturing pressure, the fracture length and on the permeability increases during the fracturing regime as observed in the laboratory tests. Notably, the numerical results gave hints on the role of the coupling between strain localization and particle transport on the formation of the pseudofractures. These findings are used to propose an updated conceptual model for the hydraulic fracturing of sand packs.

Temporal Evolution of Solute Dispersion in Three‐Dimensional Porous Rocks

AbstractWe study the temporal evolution of solute dispersion in three‐dimensional porous rocks of different heterogeneity and pore structure. To this end, we perform direct numerical simulations of pore‐scale flow and transport in a sand pack, which exhibits mild heterogeneity, and a Berea sandstone, which is characterized by strong heterogeneity as measured by the variance of the logarithm of the flow velocity. The impact of medium structure and pore‐scale mass transfer mechanisms is probed by effective and ensemble dispersion coefficients. The former is a measure for the typical width of a plume, while the latter for the deformation, that is, the spread of a mixing front. Both dispersion coefficients evolve from the molecular diffusion coefficients toward a common finite asymptotic value. Their behavior is governed by the interplay between diffusion, pore‐scale velocity fluctuations and medium structure, which determine the characteristic mass transfer time scales. We find distinctly different dispersion behaviors in the two media, which can be traced back to how particles sample pore‐scale velocity variability and how this depends on the medium structure. These are key elements for the upscaling of transport, mixing and reaction from the pore to the continuum scale.

Surfactant-polymer flood with seawater for a high temperature carbonate reservoir

Developing ultralow tension surfactant formulations for carbonate reservoirs at high temperatures (> 100 °C) in the presence of hard brine is challenging. The target carbonate reservoir had been flooded with seawater and changing of the injection brine (softening or low salinity) for enhanced oil recovery was considered expensive. Seawater was presumed to be the injection brine for this study. The goal of this research work was to develop an ultralow tension surfactant-polymer (SP) formulation with seawater for this carbonate reservoir at 115 °C and to evaluate core floods with and without salinity gradient. Phase behavior was studied for many surfactants and ultralow IFT formulations were identified with the optimal salinity near the seawater salinity. SP core floods were conducted in reservoir sand packs at 115 °C; a novel 2-oven technique was used to collect the effluent with no wax formation and minimal hydrocarbon vaporization. The residual oil saturation was reduced to less than 1% in floods with salinity gradient and about 5% in constant salinity floods (at seawater salinity). The novelty of the work lies in developing SP formulations with seawater at a high temperature and studying the effect of salinity gradient. This process can be considered for many off-shore fields which have been waterflooded with seawater.

Effects of reservoir fluids on sand packs consolidated by furan and epoxy resins: Static and dynamic states

One of the most effective methods for sand control is the chemical consolidation of sandstone structures. In this paper, the impacts of crude oil and brine in the static state and the impact of the flow rates of the fluids in the dynamic state have been assessed at the reservoir conditions. The analyses in this research were Young's modulus, compressive strength, porosity, and permeability which were done on core samples after and before fluid contact. Samples made with two different resins showed good resistance to crude oil in both states. No considerable change was seen in the analyses even at high crude oil injection rates in the dynamic state. Conversely, brine caused a noticeable change in the analyses in both states. In the presence of brine at the static state, Young's modulus and compressive strength respectively decreased by 37.5% and 34.5% for epoxy cores, whereas these parameters respectively reduced by 30% and 41% for furan cores. In brine presence at the dynamic state, compressive strength reduction was 10.28 MPa for furan and 6.28 MPa for epoxy samples and their compressive strength reached 16.75 MPa and 26.54 MPa respectively which are higher than the critical point to be known as weak sandstone core. Moreover, Young's modulus decrease values for furan and epoxy samples were respectively 0.37 GPa and 0.44 GPa. Therefore, brine had a more destructive effect on the mechanical characteristics of samples in the static state than the dynamic one for two resins. In addition, brine injection increased permeability by about 13.6% for furan and 34.8% for epoxy. Also, porosity raised by about 21.8% for furan, and 19% for epoxy by brine injection. The results showed that the chemical sand consolidation weakens in the face of brine production along with crude oil which can lead to increasing cost of oil production and treating wellbore again.