Sandstone Core Plugs Research Articles

Proof-of-concept for a probe to measure pore water pressure in oil-water saturated porous rock

The identification of the Oil/Water Contact (OWC) in a hydrocarbon reservoir is crucial for the determination of its volume and it is also important for detailed petrophysical calculations. Estimation of the OWC requires the determination of the Free Water Level (FWL). Routine practice in the oil and gas industry involves drilling multiple discovery wells since the undulation of the rock layers confining the hydrocarbon reservoir does not generally enable a single discovery well to intercept the water phase. Well drilling is expensive and industry looks forward to approaches to reduce the number of wells required for estimation of the OWC. In this context, this paper presents the proof-of-concept for a probe to measure pore water pressure in oil-water saturated porous rock. This would allow predicting the depth of the FWL in hydrocarbon reservoirs even if the single discovery well does not go through the OWC. This probe could significantly improve the appraisal process and guide the drilling campaigns, saving time, money and reducing the environmental impact of hydrocarbon search. The probe prototype was validated at laboratory scale via measurements of water pressure in core plugs saturated with water and oil. Mock-up tests on sandstone core plugs have shown that the probe can successfully measure water pressure in samples saturated with water and oil as long as the water phase is continuous in the pore space. The paper has therefore provided a proof-of-concept for a technology that can now be moved to the next readiness level.

Characterization and oil recovery enhancement by a polymeric nanogel combined with surfactant for sandstone reservoirs

The characterization and enhanced oil recovery mechanisms of a nanosized polymeric cross-linked gel are presented herein. A negatively charged nanogel was synthesized using a typical free radical suspension polymerization process by employing 2-acrylamido 2-methyl propane sulfonic acid monomer. The synthesized nanogel showed a narrow size distribution with one peak pointing to a predominant homogeneous droplet size. The charged nanogels were also able to adsorb at the oil–water interfaces to reduce interfacial tension and stabilize oil-in-water emulsions, which ultimately improved the recovered oil from hydrocarbon reservoirs. In addition, a fixed concentration of negatively charged surfactant (sodium dodecyl sulfate or SDS) was combined with different concentrations of the nanogel. The effect of the nanogels combined with surfactant on sandstone core plugs was examined by running a series of core flooding experiments using multiple flow patterns. The results show that combining nanogel and SDS was able to reduce the interfacial tension to a value of 6 Nm/m. The core flooding experiments suggest the ability of the nanogel, both alone and combined with SDS, to improve the oil recovery by a factor of 15% after initial seawater flooding.

Study of geothermal brine reinjection by microcalorimetry and core flooding experiments

SaltPower electricity generation can be used to harvest more energy from heat depleted geothermal brines. This study is an attempt to determine rock–fluid interactions by a synergy between isothermal titration calorimetry (ITC) and core flooding experiments. The results from the ITC experiments show dynamic rock–fluid and fluid–fluid interactions that take place in the reservoir upon brine reinjection. The direct implication of those dynamic interactions is the stabilization of clay particles loosely attached to the pore surfaces. Formation damage is observed when Thisted and diluted Thisted brines are reinjected into Berea sandstone core plugs. Fe(III) oxides precipitation inside the porous media is the main reason for that permeability reduction.

Spectroscopic analysis of the adsorption of carbon based nanoparticles on reservoir sandstones

The development of effective recovery techniques that can resolve the complexities of high interfacial tension (IFT), high viscosity and wettability in petroleum reservoirs will aid efforts to meet the world’s growing energy demands. Nanoparticles prove to be able to form adsorption layers on surfaces of sandstone and significantly change wettability and IFT. Despite the remarkable properties of graphene nanopaticles, not many studies have researched their potential application in EOR. In this study, sandstone coreplugs infused with crude oil, brine and carbon nanofluids (carbon nanocomposite and graphene) were characterized using field emission scanning electron microscopy (FESEM), Fourier Transform Infrared (FTIR), Raman spectroscopy, and X-ray photoelectron spectroscopy (XPS). IFT measurements were performed for oil/brine/CNPs and graphene nanofluid. The measured IFT values for brine/oil, carbon nanofluid/oil and graphene nanofluid/oil are 39–40 mN/m, 41–44 mN/m, and 9.8–11.4 mN/m, respectively. Spectroscopic analyses show that graphene has a stronger interaction (higher adsorption) on sandstone compared to the normal carbon nanoparticles, which is indicated by the lower Si–O Raman, lower FTIR transmittance for C–H peaks and the emergence of loss feature phenomenon in the XPS spectra of graphene infused with sandstone. The relatively lower FTIR transmittance intensities, well distributed carbon atoms and detected D' and D+D' Raman shifts also support the high interaction of graphene with oil and rock surface. The higher IFT reduction by graphene nanofluids is attributed to the combined high hydrophobicity and hydrophilic natures, which provides a dynamism for their detachment at the biphasic liquid/fluid interface.

An Experimental Study on Stress Sensitivity of Tight Sandstones with Different Microfractures

Aiming at the stress sensitivity problem of tight reservoirs with different microfractures, the cores of H oilfield and J oilfield with different microfractures were obtained through the fractures experiment, so as to study the change of gas permeability in tight sandstone core plug during the change of confining pressure. Besides, we use the nuclear magnetic resonance (NMR) spectra of the core before and after saturation to verify whether the core has been successfully fractured. Based on Terzaghi’s effective stress principle, the permeability damage rate (D) and the stress sensitivity coefficient (Ss) are used to evaluate the stress sensitivity of the core, which show consistency in evaluating the stress sensitivity. At the same time, we have studied the petrological characteristics of tight sandstone in detail using thin section (TS) and scanning electron microscope (SEM). The results show that the existence of microfractures is the main factor for the high stress sensitivity of tight sandstone. In addition, because of the small throat of the tight reservoir core, the throat closes when the overlying stress increases. As a result, the tight sandstone pore size is greatly reduced and the permeability is gradually reduced. Therefore, in the development of tight reservoirs, we should not only consider the complex fracture network produced by fracturing, but also pay attention to the permanent damage of reservoirs caused by stress sensitivity.

The Decisive Role of Microdispersion Formation in Improved Oil Recovery by Low-Salinity-Water Injection in Sandstone Formations

Summary Efficiency of low–salinity–water injection primarily depends on oil/brine/rock interactions. Microdispersion formation (as the dominant interfacial interaction between oil and low–salinity water) is one of the mechanisms proposed for the reported additional oil recovery by low–salinity–water injection. Using similar rock and brines, here in this work, different crude–oil samples were selected to examine the relationship between crude–oil potency to form microdispersions and improved oil recovery (IOR) by low–salinity–water injection in sandstone cores. First, the potential of the crude–oil samples to form microdispersions was measured; next, coreflood tests were performed to evaluate the performance of low–salinity–water injection in tertiary mode. Sandstone core plugs taken from a whole reservoir core were used for the experiments. The tests started with spontaneous imbibition followed by forced imbibition of high–salinity brine. Low–salinity brine was then injected in tertiary mode. The oil–recovery profiles and compositions of the produced brine were measured to investigate the IOR benefits as well as the geochemical interactions. The results demonstrate that the ratio of the microdispersion quantity to bond water is the main factor controlling the effectiveness of low–salinity–water injection. In general, a monotonic trend was observed between incremental oil recovery and the microdispersion ratio of the different crude–oil samples. In addition, it can be inferred from the results that geochemical interactions (pH and ionic interactions) would be mainly controlled by the rock's initial wettability, and also that these processes could not affect the additional oil recovery by low-salinity-water injection. To further verify the observations of geochemical interactions, a novel experiment was designed and performed on a quartz substrate to investigate the ionic interactions on the film of water between an oil droplet and a flat quartz substrate, when the high–salinity brine was replaced with the low–salinity brine. The results of the flat–substrate test indicated that the water film beneath the oil could not interact with the surrounding brine, which is in line with the results of the core tests.

Characterization of Pore Throat Size Distribution in Tight Sandstones with Nuclear Magnetic Resonance and High-Pressure Mercury Intrusion

Characterization of pore throat size distribution (PTSD) in tight sandstones is of substantial significance for tight sandstone reservoirs evaluation. High-pressure mercury intrusion (HPMI) and nuclear magnetic resonance (NMR) are the effective methods for characterizing PTSD of reservoirs. NMR T2 spectra is usually converted to mercury intrusion capillary pressure for PTSD characterization. However, the conversion is challenging in tight sandstones due to tiny pore throat sizes. In this paper, the linear conversion method and the nonlinear conversion method are investigated, and the error minimization method and the least square method are proposed to calculate the conversion coefficients of the linear conversion method and the nonlinear conversion method, respectively. Finally, the advantages and disadvantages of these two different conversion methods are discussed and compared with field case study. The research results show that the average linear conversion coefficients of the 20 tight sandstone core plugs collected from Yanchang Formation, Ordos Basin of China is 0.0133 μm/ms; the average nonlinear conversion coefficient is 0.0093 μm/ms and the average nonlinear conversion exponent is 0.725. Although PTSD converted from NMR spectra by the nonlinear conversion method is wider than that obtained from linear conversion method, the nonlinear conversion method can retain the characteristic of bi-modal distribution in PTSD.

Evaluation of Measured Differences in Liquid versus Gas Permeability and Identification of Potential Causes

Clay and fines migration within sandstone core plugs was investigated to refine permeability estimates for the CO2 EOR project being conducted at the Bell Creek Oil Field. Laboratory tests include porosity, air permeability, brine permeability, and x-ray diffraction and were conducted on reservoir samples at 17.2 MPa and 40.5°C. Results show a decrease in brine permeability when compared to the klinkenberg calculated air permeability. Clay and fines migration has been ruled out through post-brine air permeability testing. Through this study, modifications to the currently used air to brine correction factors have been proposed and used to refine reservoir simulations.

Investigation on Flow Behaviour in Porous Media During Water Flooding and Following CO2 Flooding Using MRI

This article addresses the use of MRI technique to follow the process of oil, water, supercritical CO2 multiphase flow in consolidated sandstone core plug at a typical reservoir temperature and pressure condition. 2D images at various times and quantitative saturation curves were obtained during all stages of the flooding process. The fronts and interfaces between displaced and displacing fluids were also dynamics monitored in situ during water and subsequent supercritical CO2 flooding process. The results showed that the process of CO2 flooding enhanced oil recovery more than 10% based on the previous water flooding. A method of predicting the relative permeability and capillary pressure curves was successfully extended and applied to CO2 flooding, the capillary pressure, the wetting and non-wetting phase relative permeability curves were simultaneously estimated from the capillary end saturation profiles, which were measured with MRI technique. These curves are important and required in various reservoir simulations for evaluating hydrocarbon recovery processes.

A multi-scale experimental study of crude oil-brine-rock interactions and wettability alteration during low-salinity waterflooding

In this study we present the results of a multi-scale experimental investigation of the mechanisms responsible for the increased oil recovery by low-salinity waterflooding (LSWF), i.e., low-salinity effect (LSE). Using core- and substrate-flooding experiments as well as imaging techniques at macro, micro, and nanometer scales, we probe the intricate crude oil-brine-rock interactions and the subtle pore-scale displacement events governing recovery enhancement during LSWF. We performed several LSWF and high-salinity waterflooding (HSWF) experiments on macro-scale (1 inch-diameter) reservoir sandstone core plugs while collecting effluent samples for further analysis.LSWF experiments exhibited a prolonged oil recovery response and notably higher oil recovery compared to HSWF. Imaging effluent samples, at sub-nanometer resolutions using transmission electron microscopy, demonstrated significant fines mobilization during LSWF. The occurrence of electric double layer expansion (DLE) as a source of fines mobilization during LSWF was confirmed by examining scanning electron microscopy images of the reservoir rock substrates before and after contacting the low-salinity brine. Moreover, geochemical analysis of the effluent samples showed evidence of proton excahnge and multi-component ion exchange (MIE) during LSWF. The mobilization of fine particles (due to DLE) and the ion exchange processes are believed to result in removal of oil molecules from the rock surfaces leading to an enhancement in oil recovery as well as alteration of wettability toward increased water-wetness. These observations were then linked to our findings from an earlier study during which LSWF and HSWF experiments were conducted on miniature (5 mm-diameter) core samples while the pore space was being imaged at micrometer resolution. In-situ oil/brine contact angles measured during flow tests conducted on the miniature core samples revealed a significant level of wettability alteration from weakly oil-wet toward increased water-wetness during LSWF. Analysis of fluid occupancy maps showed that this change in wettability lowers the threshold water pressure needed for water-displacing-oil events to take place in the pore elements, which in turn enhances displacement efficiency and oil recovery.

Experimental investigation of carboxylate-alumoxane nanoparticles for the enhanced oil recovery performance

In this study, two nanoparticle types of functionalized alumina (functionalized boehmite and functionalized pseudo-boehmite which are named B.MA-Alumoxane and S.B.MA-Alumoxane, respectively) were produced by the sol-gel method and were dispersed in deionized water without surfactants. Field emission scanning electron microscopy (FE-SEM) images were taken to observe morphology of the nanoparticles, type of the functional group was characterized by Fourier-transform infrared spectroscopy (FT-IR), zeta potential analysis was conducted for investigating the stability of the nanofluids, the nanoparticles size distribution was measured by dynamic light scattering (DLS), and also Brunauer–Emmett–Teller (BET) analysis was performed to characterize the surface properties of the prepared nanoparticles. For studying the application of these nanofluids in enhanced oil recovery (EOR), nanofluids with different concentrations (200, 300, 400, and 500 ppm) of each nanoparticle were prepared. The interfacial tensions (IFT) of nanofluids with crude oil were measured by pendant drop method and wettability alteration of oil-wet sandstone rock samples was investigated via contact angle measurement method when they were exposed to nanofluids. In order to investigate the adsorption of the nanoparticles on the sandstone rocks, the adsorption tests were performed. In following, micromodel tests were done to observe the effect of nanoparticles in displacing oil from the porous media of the glass micromodel. Coreflood tests were performed in order to observe the application of carboxylate-alumoxane nanofluids in sandstone core plugs. The morphology of S.B.MA-Alumoxane nanoparticle is as agglomerated particles and B.MA-Alumoxane has nanosheet morphology. The size distribution for S.B.MA-Alumoxane and B.MA-Alumoxane is 12 nm to 35 nm and 32 nm to 155 nm, respectively. By increasing the concentration of nanoparticles, IFT value was reduced from 19.34 mN/m for deionized water to 8.52 mN/m for 500 ppm S.B.MA-Alumoxane and to 11.84 mN/m for 500 ppm B.MA-Alumoxane. The rock samples also became more water-wet in higher concentrations of both nanoparticle types. S.B.MA-Alumoxane showed better performance in comparison to B.MA-Alumoxane. The micromodel test showed the maximum increase of 52% in oil recovery for S.B.MA-Alumoxane and 33% for B.MA-Alumoxane with respect to deionized water. Moreover, coreflood test shows that S.B.MA-Alumoxane has better performance in comparison with B.MA-Alumoxane at the concentration of 500 ppm. In this research, for the first time Carboxylate–Alumoxane nanoparticles were used in EOR by two different morphologies and sizes. The smaller size and higher specific surface area of S.B.MA-Alumoxane in comparison with B.MA-Alumoxane provide its better performance in enhanced oil recovery.

Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs

Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.

Application of low-field, 1H/13C high-field solution and solid state NMR for characterisation of oil fractions responsible for wettability change in sandstones

Asphaltene adsorption on solid surfaces is a standing problem in petroleum industry. It has an adverse effect on reservoir production and development by changing rock wettability, plugging pore throats, and affects oil transport through pipelines. Asphaltene chemistry constitutes important part of the ageing process as part of petrophysical studies and core analysis. The mechanisms and contribution of various oil components to adsorption processes is not fully understood. To investigate the kinetics of the ageing process and address the relative contribution of different oil components, we prepared three sets of sandstone core plugs aged in different oil mixtures over various time intervals. Cores were then re-saturated with decane to evaluate their wetting state using low-field NMR relaxometry by monitoring a change of surface relaxivity. Adsorbed deposits were then extracted from cores for solution-state NMR analysis. Their 1H and 1H-13C correlation spectra obtained using heteronuclear single quantum coherence (HSQC) technique were matched to spectra of four SARA (saturates, aromatics, resins and asphaltenes) components of oil mixtures to deduce components of deposits and inter-component interactions. We notice that wettability reversal of rock is inversely proportional to initial asphaltene concentration. Analysis of deposits reveals an increase in their aliphatic content over ageing time, which is accompanied by a change of the morphology of the pore space due to cluster aggregates forming a network. Results suggest that the ageing process in respect to the wetting state of rock samples consists of three distinctive stages: (i) an early-time period, when the fraction of most polar asphaltenes creates a discontinuous layer corresponding to mixed-wet state; (ii) an intermediate-time interval, at which the full grain coverage may be achieved (at favourable chemical environment) corresponding to strong oil-wetting; (iii) a late-time stage, where intense macro-aggregates accumulation occurs, changing the pore space integrity. It is likely asphaltene-aliphatic interactions leading to growth of sub-micron size macro-aggregates.

Oil-soluble contrast agents for NMR

In well logging applications, nuclear magnetic resonance (NMR) is recognized as a powerful tool to differentiate various fluids inside porous media. However, it can be challenging to do so in complex situations, e.g. when fluid peaks overlap with each other. Water-soluble contrast agents, such as MnCl2 or Gd-EDTA, have been proposed for use to accelerate the water relaxation, thus separating the water signal from those of other fluids. Together with these contrast agents, the log-inject-log method is used and the difference between the two logs is attributed to the doped water phase. This application only works with water-based mud. To extend its use to oil-based mud (OBM), it is desirable to find alternatives to water-soluble contrast agents that are compatible with OBM.In this work, we introduce a new group of doping agents: oil-soluble contrast agents. We selected several iron-based complex compounds that are oil-soluble, and tested and evaluated their effects on oil signal relaxation using a laboratory NMR apparatus. We also tested hydrophobic iron oxide nanoparticles as a contrast agent. The results showed that both the complex compounds and nanoparticles were able to reduce the transverse relaxation time of oil from longer than 2 s to less than 20 ms. To demonstrate their applicability in porous media, we injected doped oil into gas-saturated Berea sandstone and limestone core plugs. With conventional 1D NMR measurements or the use of water-soluble contrast agents, it is not straightforward to discern the gas signal from the OBM signal. Our experiments showed that the gas signal could be easily identified in the presence of doped oil via simple T2 scans. We also performed experiments to demonstrate that the peaks of water and doped oil could be readily differentiated.The use of oil-soluble doping agents can significantly enhance the contrast of the NMR signals originated from different formation fluids, thus facilitating the fluid typing process. It provides a key alternative to the current water-doping technique. It is particularly advantageous when changing the oil relaxation is desired, such as for eliminating signal interferences from OBM invasion and differentiating heavy oil from clay-bound water. It also provides the possibility of speeding up the logging process by dramatically reducing the oil relaxation time. In addition, they can be employed in the laboratory for various purposes such as water saturation determination and fluid displacement monitoring. These contrast agents can also be of useful when oil-soluble contrast agents are desired in other fields, such as medical imaging applications.

Riding the Right Wavelet: Quantifying Scale Transitions in Fractured Rocks

AbstractThe mechanics of brittle failure is a well‐described multiscale process that involves a rapid transition from distributed microcracks to localization along a single macroscopic rupture plane. However, considerable uncertainty exists regarding both the length scale at which this transition occurs and the underlying causes that prompt this shift from a distributed to a localized assemblage of cracks or fractures. For the first time, we used an image analysis tool developed to investigate orientation changes at different scales in images of fracture patterns in faulted materials, based on a two‐dimensional continuous wavelet analysis. We detected the abrupt change in the fracture pattern from distributed tensile microcracks to localized shear failure in a fracture network produced by triaxial deformation of a sandstone core plug. The presented method will contribute to our ability of unraveling the physical processes at the base of catastrophic rock failure, including the nucleation of earthquakes, landslides, and volcanic eruptions.

Three-Phase Flow in Fractured Porous Media: Investigation of Matrix/Fracture Interactions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181891, “Three-Phase Flow in Fractured Porous Media: Experimental Investigation of Matrix/Fracture Interactions,” by M. Sabti, A.H. Alizadeh, and M. Piri, University of Wyoming, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed. The authors present the results of a detailed experimental study in which underlying pore-level-displacement physics of two- and three-phase flow in a fractured rock sample is investigated with high-resolution X-ray microtomography techniques. A unique, three-phase coreflooding setup integrated with a microcomputed-tomography (micro-CT) scanner is used to conduct flow experiments on a miniature, partially fractured sandstone sample to shed light on subtle displacement mechanisms governing matrix/fracture interactions in the presence or absence of spreading oil layers. Experimental Methodology Rock and Fluid Properties. A water-wet Berea sandstone core plug, 38 mm in diameter and 100 mm in length, was subjected to continuous, nonuniform stress to create a fracture parallel to the stress axis. The artificial fracture was induced such that it ran through only half of the core plug. This configuration was used to study pore-fluid occupancies and displacement physics at different locations of the medium including matrix-only sites, the fracture, and the matrix adjacent to the fracture. After inducing the fracture, a miniature sample, 10 mm in diameter and 40 mm in length, was cut from the core plug. The coreflooding tests were carried out with two different fluid systems representing the spreading and nonspreading conditions. X-ray dopants were added to liquid phases to establish sufficient contrasts among all phases (i.e., brine, oil, and gas) during the image-processing steps. All fluids were recirculated through the coreflooding setup before starting the experiment, bypassing the core sample at the experimental conditions for a period of time (i.e., 48 hours) sufficient to equilibrate all the phases and minimize mass transfer between the fluids in the core sample during the experiments. Experimental Procedure. The experimental apparatus included three major modules: (1) a three-phase closed-loop miniature coreflooding setup, (2) a high-resolution micro-CT scanner, and (3) a data-acquisition system. The flow tests were carried out at pore pressure of 3.45 MPa and ambient temperature (20°C). Each fluid was retracted from a specific section of the separator on the basis of the density of the fluid and then injected into the core sample. The authors used the unsteady-state approach, in which only one fluid is injected at a time.

Nanotechnology for improved CO2 utilization in CCS: Laboratory study of CO2-foam flow and silica nanoparticle retention in porous media

Underground CO2 storage may reduce anthropogenic CO2 emissions, but suffer from detrimental flow instabilities mainly from development of viscous fingers and density segregation that arise at larger scales. Suggested approaches to mitigate reduction in CO2 utilization include mobility control, conformance modifications and CO2 thickeners, where CO2 foams have been shown as one of the most promising techniques. We present laboratory results that study foam generation and flow by adding hydrophilic silica nanoparticles during co-injection with liquid CO2 in sandstone core plugs to reduce CO2 mobility. Nanoparticle retention characteristics in the porous media is essential to CO2-foam flow strategies: high degree of retention may, in addition to reducing foamability, be detrimental to fluid injectivity if particle accumulation reduce the formation fluid flow capacity near the injection well. Retention was 401μg/g, in the lower range of reported literature values for aqueous surfactants, suggesting that nanoparticles to a large degree remain at the CO2-brine interface to stabilize foam when flowing through the porous medium. Elution, recovery of nanoparticles from the pore space by re-mobilization, was 79μg/g. Hence, 20% of retained nanoparticles were re-mobilized, and will contribute positively in a field application to increase foam stability further from the injection well. An apparent foam viscosity hysteresis related to the average gas saturation was observed when drainage-like (increasing gas fractions) and imbibition-like (decreasing gas fractions) injection strategies were compared. Nanoparticle-stabilized foam was also compared with surfactant-stabilized foam and the following main differences were observed: 1) maximum surfactant-stabilized foam apparent viscosities occurred at fg=0.9, compared with nanoparticle-stabilized foam with fg=0.7 (drainage-like) and fg=0.35 (imbibition-like); 2) without the presence of oil surfactant-stabilized foam have a higher (three orders of magnitude) apparent viscosity compared with nanoparticle-stabilized foam; 3) shear-thinning behavior was observed with surfactant-stabilized foam, whereas close to Newtonian behavior was observed with nanoparticle-stabilized foam; 4) no hysteresis was observed with surfactant-stabilized foams, whereas a clear hysteresis was observed with nanoparticle-stabilized foam.

Improving the microscopic sweep efficiency of water flooding using silica nanoparticles

Fluid/fluid and fluid/rock interfaces have large influence on the microscopic sweep efficiency of an enhanced oil recovery process. Therefore, modification of these interfaces using nanoparticles to suitable conditions might lead to better recovery factors. Particularly, wettability alteration and interfacial tension reduction are the two key mechanisms which should be considered. This study was designed to address the capability of nanoparticles to be used as a chemical agent for enhanced oil recovery by several core flooding experiments. The injected chemical solution was prepared using synthetic brine containing %3 NaCl, silica nanoparticles, and SDS surfactant. Contact angle in rock/oil/solution system and interfacial tension between oil/solution were measured. In addition, SEM pictures and XRD analysis were taken to conduct a more thorough investigation of effect of nanoparticles on sandstone core plugs. Nanoparticles and surfactant mixture were flooded with various concentrations under different scenarios. The results show the incremental oil recovery of nanoparticles floods in sandstone core samples which ranged from 4.85 to 11.7%. Conversely, the enhanced oil recovery of high concentration of nanoparticle floods in cores was small. It is deduced that the mechanisms responsible for incremental oil recovery are mainly interfacial tension reduction and wettability alteration toward water-wet condition. However, the flooding results as well as experimental study of possible retention revealed that nanoparticles can be considered as an effective chemical agent in enhanced oil recovery.

Spontaneous imbibition in asymmetric branch-like throat structures in unconventional reservoirs

Unconventional reservoirs, especially shale plays, have abundant micro-nano pores. Large volume water was injected into the reservoir during hydraulic fracturing. Fracturing fluid can displace gas in pore spaces spontaneously, called spontaneous imbibition (SI), which has significant effects on the gas production after hydraulic fracturing. Throat structure in matrix is one of the key factors to influence SI process. In this work, at first, complex pore space is simplified as a spatial self-similar branch-like structure composed of several asymmetric sub-throats. Then, within asymmetric branch structure, the imbibition process is calculated by a newly established mathematical model, and the influence of both pore structure and fluid characteristics, including contract angle, viscosity, surface tension, are discussed. Finally, some lab experiments, especially SI tests, are included on shale and sandstone core plugs to verify our model. Results show that the coherence in wettability between the reservoir and the fracturing fluid is important to enhance the microscopic replacement effect. Pore size also has effect influence on imbibition curve. In addition, both in models and experiments, imbibition index n is useful to describe imbibition properties of rocks. In unconventional rock samples like shale, n is less than 0.4, while high-permeability sandstone, n approach to 0.5. These conclusions are useful to investigate the mechanism of spontaneous imbibition and microscopic displacement in unconventional reservoirs.

Application of a water based nanofluid for wettability alteration of sandstone reservoir rocks to preferentially gas wetting condition

Condensate and water banking around gas condensate wells result in vital well deliverability issues. Wettability alteration of near wellbore region to gas wetting condition is known to be the most novel and the only permanent method, to improve condensate well productivity. In this work, a water based nanofluid is used to change the wettability of sandstone reservoir rocks from strongly liquid wetting to intermediate gas wetting condition. Static contact angle measurements demonstrated significant increase of liquid phase contact angle as a result of chemical treatment with SurfaPore M nanofluid. The characteristics of SurfaPore M adsorption on sandstone rock are quantified through kinetic and equilibrium adsorption studies, as well as the stability of the used chemical against NaCl brine salinity in ambient condition,. Air/liquid spontaneous imbibition tests along with core flooding experiments were utilized to study the effect of wettability on two phase fluid flow through porous media. It has been concluded that kinetic behavior of SurfaPore M-sandstone system conforms pseudo-second order, while Freundlich isotherm matches the equilibrium adsorption data; these results eventuate multilayer chemisorption of NPs on sandstone surface. The results of spontaneous imbibition tests showed remarkable decrease of the ultimate amount of imbibed liquid by factors of 0.09 and 0.17 for n-decane and water, respectively. Also, the results of water injection experiments demonstrated the increase in liquid phase mobility by a factor of 3.2 as a result of surface modifiers in high permeability sandstone core plug. Furthermore, it is concluded that the utilized nanofluid is better to be used in high permeability sandstone rocks. The results of this research pave the way for possible future field applications of SurfaPore M nanofluid chemical in gas condensate reservoirs to alleviate production difficulties.