scholarly journals Dos and Don’ts When Developing a System to Investigate Spontaneous Imbibition in Unconsolicdated Porous Media

2019 ◽  
Vol 89 ◽  
pp. 01005 ◽  
Author(s):  
Bergit Brattekås ◽  
Tore L. Føyen ◽  
Trond Vabø ◽  
Håkon Haugland ◽  
Simon I. Reite ◽  
...  
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Fluid Dynamic ◽  
Water Soluble ◽  
Spontaneous Imbibition ◽  
Displacement Front ◽  
Wide Range ◽  
Unconsolidated Porous Media ◽  
The Impact ◽  
Wetting Fluid

This paper describes the development of a consistent model system to measure spontaneous imbibition and determine saturation functions in unconsolidated porous media. Sand grains or glass beads were packed in up to 0.5 m long, transparent glass tubes with optical access to local saturation development during spontaneous imbibition processes. The Two Ends Open-Free spontaneous imbibition (TEOFSI) boundary condition was used, where one end face is exposed to the wetting fluid and the other end to the non-wetting fluid. Dynamic measurement of the advancing displacement front and volumetric production from each open end-face enabled estimation of capillary pressure and relative permeability for the system. A range of wetting- and non-wetting phase viscosities and viscosity ratios was used during spontaneous imbibition in unconsolidated sand or glass packs. Wetting phase (water) viscosity was increased using water soluble glycerol or polymers. Air or mineral oil of varying composition provided a wide range of non-wetting phase viscosities. High permeable systems are extremely sensitive to laboratory properties, which may dominate the viscous resistance and determine flow behaviour. Systematic discrepancies observed in early testing indicated that end effects were present, even in long systems, in the filters at each end of the glass tube to maintain the grains or beads in place. Different filters were tested (no filter, glass, paper and micro-porous discs) to determine the impact of the filter on spontaneous imbibition. In addition to slower oil recovery than anticipated, developmentof a non-uniform displacement front was observed, demonstrating the large influence from minute heterogeneities within the packs, and at the end faces. A standard sand grain packing procedure, using a custom-designed packing device, was therefore developed to ensure homogeneous properties throughout theporous media, and limited the spread in porosity and permeability values. Homogeneous sand packs with reproducible properties are necessary, to systematically investigate flow parameters and changes in wettability in unconsolidated porous media.

Capillary Impregnation of Viscous Fluids in a Multi-Layered Porous Medium

2019 ◽  
Author(s):  
Shabina Ashraf ◽  
Jyoti Phirani
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Viscous Fluids ◽  
Spontaneous Imbibition ◽  
Lab On Chip ◽  
Capillary Impregnation ◽  
Relative Placement ◽  
Homogeneous Porous Medium ◽  
Wetting Fluid

Abstract Capillary impregnation of viscous fluids in porous media is useful in diagnostics, design of lab-on-chip devices and enhanced oil recovery. The impregnation of a wetting fluid in a homogeneous porous medium follows Washburn’s diffusive law. The diffusive dynamics predicts that, with the increase in permeability, the rate of spontaneous imbibition of a wetting fluid also increases. As most of the naturally occurring porous media are composed of hydrodynamically interacting layers having different properties, the impregnation in a heterogeneous porous medium is significantly different from a homogeneous porous medium. A Washburn like model has been developed in the past to predict the imbibition behavior in the layers for a hydrodynamically interacting three layered porous medium filled with a non-viscous resident phase. It was observed that the relative placement of the layers impacts the imbibition phenomena significantly. In this work, we develop a quasi one-dimensional lubrication approximation to predict the imbibition dynamics in a hydrodynamically interacting multi-layered porous medium. The generalized model shows that the arrangement of layers strongly affects the saturation of wetting phase in the porous medium, which is crucial for oil recovery and in microfluidic applications.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

Surfactant Retention in Berea Sandstone- Effects of Phase Behavior and Temperature

1982 ◽  
Vol 22 (06) ◽  
pp. 962-970 ◽  
Author(s):  
J. Novosad
Keyword(s):  
Porous Media ◽  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Liquid Interface ◽  
Divalent Ions ◽  
Surfactant Precipitation ◽  
Wide Range ◽  
Solid Liquid Interface ◽  
Solid Liquid

Novosad, J., SPE, Petroleum Recovery Inst. Abstract Experimental procedures designed to differentiate between surfactant retained in porous media because of adsorption and surfactant retained because Of unfavorable phase behavior are developed and tested with three types of surfactants. Several series of experiments with systematic changes in one variable such as surfactant/cosurfactant ratio, slug size, or temperature are performed, and overall surfactant retention then is interpreted in terms of adsorption and losses caused by unfavorable phase behavior. Introduction Adsorption of surfactants considered for enhanced oil recovery (EOR) applications has been studied extensively in the last few years since it has been shown that it is possible to develop surfactant systems that displace oil from porous media almost completely when used in large quantities. Effective oil recovery by surfactants is not a question of principle but rather a question of economics. Since surfactants are more expensive than crude oil, development of a practical EOR technology depends on how much surfactant can be sacrificed economically while recovering additional crude oil from a reservoir.It was recognized earlier that adsorption may be only one of a number of factors that contribute to total surfactant retention. Other mechanisms may include surfactant entrapment in an immobile oil phase surfactant precipitation by divalent ions, surfactant precipitation caused by a separation of the cosurfactant from the surfactant, and surfactant precipitation resulting from chromatographic separation of different surfactant specks. The principal objective of this work is to evaluate the experimental techniques that can be used for measuring surfactant adsorption and to study experimentally two mechanisms responsible for surfactant retention. Specifically, we try to differentiate between the adsorption of surfactants at the solid/liquid interface and the retention of the surfactants because of trapping in the immobile hydrocarbon phase that remains within the core following a surfactant flood. Measurement of Adsorption at the Solid/Liquid Interface Previous adsorption measurements of surfactants considered for EOR produced adsorption isotherms of unusual shapes and unexpected features. Primarily, an adsorption maximum was observed when total surfactant retention was plotted against the concentration of injected surfactant. Numerous explanations have been offered for these peaks, such as a formation of mixed micelles, the effects of structure-forming and structurebreaking cations, and the precipitation and consequent redissolution of divalent ions. It is difficult to assess which of these effects is responsible for the peaks in a particular situation and their relative importance. However, in view of the number of physicochemical processes taking place simultaneously and the large number of components present in most systems, it seems that we should not expect smooth monotonically increasing isotherms patterned after adsorption isothemes obtained with one pure component and a solvent. Also, it should be realized that most experimental procedures do not yield an amount of surfactant adsorbed but rather a measure of the surface excess.An adsorption isotherm, expressed in terms of the surface excess as a function of an equilibrium surfactant concentration, by definition must contain a maximum if the data are measured over a sufficiently wide range of concentrations. SPEJ P. 962^

scholarly journals Impact of Brine Composition and Concentration on Capillary Pressure and Residual Oil Saturation in Limestone Core Samples

2019 ◽  
Vol 89 ◽  
pp. 02006
Author(s):  
F. Feldmann ◽  
A. M. AlSumaiti ◽  
S. K. Masalmeh ◽  
W. S. AlAmeri ◽  
S. Oedai
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Spontaneous Imbibition ◽  
Oil Saturation ◽  
Salinity Effect ◽  
Connate Water ◽  
Low Salinity ◽  
Remaining Oil ◽  
The Impact ◽  
Secondary Mode

Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

scholarly journals Wettability control on multiphase flow in patterned microfluidics

2016 ◽  
Vol 113 (37) ◽  
pp. 10251-10256 ◽  
Author(s):  
Benzhong Zhao ◽  
Christopher W. MacMinn ◽  
Ruben Juanes
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Contact Angles ◽  
Flow In Porous Media ◽  
Wetting Transition ◽  
Pore Scale ◽  
Displacement Efficiency ◽  
Pore Filling ◽  
Wide Range ◽  
The Impact

Multiphase flow in porous media is important in many natural and industrial processes, including geologic CO2 sequestration, enhanced oil recovery, and water infiltration into soil. Although it is well known that the wetting properties of porous media can vary drastically depending on the type of media and pore fluids, the effect of wettability on multiphase flow continues to challenge our microscopic and macroscopic descriptions. Here, we study the impact of wettability on viscously unfavorable fluid–fluid displacement in disordered media by means of high-resolution imaging in microfluidic flow cells patterned with vertical posts. By systematically varying the wettability of the flow cell over a wide range of contact angles, we find that increasing the substrate’s affinity to the invading fluid results in more efficient displacement of the defending fluid up to a critical wetting transition, beyond which the trend is reversed. We identify the pore-scale mechanisms—cooperative pore filling (increasing displacement efficiency) and corner flow (decreasing displacement efficiency)—responsible for this macroscale behavior, and show that they rely on the inherent 3D nature of interfacial flows, even in quasi-2D media. Our results demonstrate the powerful control of wettability on multiphase flow in porous media, and show that the markedly different invasion protocols that emerge—from pore filling to postbridging—are determined by physical mechanisms that are missing from current pore-scale and continuum-scale descriptions.

scholarly journals Comparative Study of Using Sea-Water for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs: Effects of Temperature and Aging Time on Oil Recovery

2018 ◽  
Vol 7 (2) ◽  
pp. 1-13
Author(s):  
Madi Abdullah Naser ◽  
Mohamed Erhayem ◽  
Ali Hegaig ◽  
Hesham Jaber Abdullah ◽  
Muammer Younis Amer ◽  
...  
Keyword(s):  
Aging Time ◽  
Oil Recovery ◽  
Sea Water ◽  
Essential Element ◽  
Recovery Process ◽  
Spontaneous Imbibition ◽  
Effect Of Temperature ◽  
Injection Process ◽  
Reservoir Conditions ◽  
The Impact

Oil recovery process is an essential element in the oil industry, in this study, a laboratory study to investigate the effect of temperature and aging time on oil recovery and understand some of the mechanisms of seawater in the injection process. In order to do that, the sandstone and carbonate cores were placed in the oven in brine to simulate realistic reservoir conditions. Then, they were aged in crude oil in the oven. After that, they were put in the seawater to recover, and this test is called a spontaneous imbibition test. The spontaneous imbibition test in this study was performed at room temperature to oven temperature 80 oC with different sandstone and carbonate rock with aging time of 1126 hours. The result shows that the impact of seawater on oil recovery in sandstone is higher than carbonate. At higher temperature, the oil recovery is more moderate than low temperature. Likewise, as the aging time increase for both sandstone and carbonate rocks the oil recovery increase. 

Numerical Simulations of Surfactant Flooding in Carbonate Reservoirs: The Impact of Geological Heterogeneities Across Scales

2021 ◽  
Author(s):  
Jackson Pola ◽  
Sebastian Geiger ◽  
Eric Mackay ◽  
Christine Maier ◽  
Ali Al-Rudaini
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Spontaneous Imbibition ◽  
Numerical Dispersion ◽  
Surfactant Flooding ◽  
Production Forecast ◽  
Geological Heterogeneity ◽  
Grid Coarsening ◽  
The Impact ◽  
The Way

Abstract We demonstrate how geological heterogeneity impacts the effectiveness of surfactant-based enhanced oil recovery (EOR) at larger (inter-well and sector) scales when upscaling small (core) scale heterogeneity and physicochemical processes. We used two experimental datasets of surfactant-based EOR where spontaneous imbibition and viscous displacement, respectively dominate recovery. We built 3D core-scale simulation models to match the data and parameterize surfactant models. The results were deployed in high-resolution models that preserve the complexity and heterogeneity of carbonate formations in the inter-well and sector scale. These larger-scale models were based on two outcrop analogues from France and Morroco, respectively, which capture the reservoir architectures inherent to the productive carbonate reservoir systems in the Middle East. We then assessed and quantified the error in production forecast that arises due to upscaling, upgridding, and simplification of geological heterogeneity. Simulation results showed a broad range of recovery predictions. The variability arises from the choice of surfactant model parameterization (i.e., spontaneous imbibition vs viscous displacement) and the way the heterogeneity in the inter-well and sector models was upscaled and simplified. We found that the parameterization of surfactant models has a significant impact on recovery predictions. Oil recovery at the larger scale was observed to be higher when using the parametrization derived from viscous displacement experiments compared to parameterization from spontaneous imbibition experiments. This observation clearly demonstrated how core-scale processes impact recovery predictions at the larger scales. Also, the variability in recovery prediction due to the choice of surfactant model was as large as the variability arising from upscaling and upgridding. Upscaled and upgridded models overestimated recovery because of the simplified geology. Grid coarsening exacerbated this effect because of the increased numerical dispersion. These results emphasize the need to use correctly configured surfactant models, appropriate grid resolution that minimizes numerical dispersion, and properly upscaled reservoir models to accurately forecast surfactant floods. Our findings present new insights into how the uncertainty in production forecasts during surfactant flooding depends on the way surfactant models are parameterized, how the reservoir geology is upscaled, and how numerical dispersion is impacted by grid coarsening.

A numerical study of particle migration in porous media during produced water reinjection

2021 ◽  
pp. 1-34
Author(s):  
Tian Xia ◽  
Qihong Feng ◽  
Sen Wang ◽  
Qinglin Shu ◽  
Yigen Zhang ◽  
...  
Keyword(s):  
Particle Size ◽  
Porous Media ◽  
Oil Recovery ◽  
Produced Water ◽  
Numerical Study ◽  
Particle Diameter ◽  
Particle Migration ◽  
Critical Ratio ◽  
Clear Understanding ◽  
The Impact

Abstract The clogging phenomenon often occurs during the reinjection of produced water due to the suspended particles, which will deteriorate the development efficiency. Many experimental and analytical methods have been introduced to solve this problem; however, few numerical approaches have been proposed to investigate the particle migration in the produced water reinjection process. Moreover, it is hard to obtain a clear understanding directly from the particle scale when the injected particles have different sizes. This paper employs a coupled lattice Boltzmann method and discrete element method (LBM-DEM) to study the aforementioned process. The method was validated by reproducing the Drafting-Kissing-Tumbling (DKT) process. Simulations of migration of injected particles with different sizes through porous media were conducted and three clogging scenarios had been identified. We investigated the impact of injected particle size distribution and porous media on particle migration and concluded the results in the polydisperse aspect. From the simulation, we can conclude that mix clogging is the scenario we should try to avoid. Besides, both critical ratio of particle diameter of porous media to median particle diameter of injected particles (D/d50) and critical standard deviation value exist. The particle size range should be as small as possible in economical limits and the D/d50 value should be larger than the critical value. Our results can provide a good guide for the produced water pretreatment, which can improve oil recovery.

Impact of condition monitoring on reciprocating compressor efficiency

2018 ◽  
Vol 24 (4) ◽  
pp. 529-543 ◽  
Author(s):  
Jim Townsend ◽  
M. Affan Badar
Keyword(s):  
Condition Monitoring ◽  
Oil Recovery ◽  
Economic Benefits ◽  
Temperature Monitoring ◽  
Strong Impact ◽  
Pressure Monitoring ◽  
Monitoring Technology ◽  
Content Type ◽  
Wide Range ◽  
The Impact

Purpose Reciprocating compressors offer an efficient method of compressing almost any gas composition in a wide range of pressures and have numerous applications. Condition monitoring of critical rotating machinery is widely accepted by operators of centrifugal compressors. However, condition monitoring of reciprocating machinery has not received the same degree of acceptance. An earlier study (Townsend et al., 2016) was conducted on temperature monitoring. The purpose of this paper is to examine the impact of continuous pressure monitoring on electric-driven compressors. Design/methodology/approach This research analyzes the impact of continuous pressure monitoring on a fleet of 14 compressors transporting CO2 for enhanced oil recovery. The reliability and efficiency data on 14 reciprocating compressors over a three-year period were analyzed for failures detectable by the condition monitoring technology. The engineering economic analysis is presented to determine the impact this technology will have on the productivity of the compressors. Findings The study considers utilizing condition monitoring technology to analyze the pressure of the swept volume of the compressor cylinders. The results of the study indicate that continuous pressure monitoring technology has a strong impact on the productivity of the compressor fleet. The internal rate of return not only exceeds the operators hurdle rate, but the payback period is also dramatic. Pressure monitoring was found to be economically better than temperature monitoring. Originality/value The study reveals the economic benefits of implementing condition monitoring in the form of continuous pressure monitoring on reciprocating compressors.

The impact of heterogeneous anisotropy of porous media on density-driven convection

2019 ◽  
Vol 30 (2) ◽  
pp. 956-976
Author(s):  
Qian Li ◽  
Weihua Cai ◽  
Xiaojing Tang ◽  
Yicheng Chen ◽  
Bingxi Li ◽  
...  
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Pseudospectral Method ◽  
Heterogeneous Porous Media ◽  
Saline Aquifers ◽  
Anisotropic Permeability ◽  
Content Type ◽  
Monotonic Trend ◽  
The Impact

Purpose The aim of this study is to numerically simulate the density-driven convection in heterogeneous porous media associated with anisotropic permeability field, which is important to the safe and stable long term CO2 storage in laminar saline aquifers. Design/methodology/approach The study uses compact finite difference and the pseudospectral method to solve Darcy’s law. Findings The presence of heterogeneous anisotropy may result in non-monotonic trend of the breakthrough time and quantity of CO2 dissolved in the porous medium, which are important to the CO2 underground storage. Originality/value The manuscript numerically study the convective phenomena of mixture contained CO2 and brine. The phenomena are important to the process of CO2 enhanced oil recovery. Interesting qualitative patterns and quantitative trends are revealed in the manuscript.

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