Decreasing Water Saturation Research Articles

Retained water content after nitrogen driving water on flooding saturated high volatile bituminous coal using low-field nuclear magnetic resonance

Retained water in reservoirs can result in water block damage that can lead to low productivity of coalbed methane wells. To research the water saturation increasing process during water flooding and determine the retained water content variation law after nitrogen driving water, considering that high-pressure nitrogen injection is recently regarded as an effective technology to enhance CBM well production, multiple low-field nuclear magnetic resonance methods, including T2 spectrum testing, multi-slice spin-echo sequence imaging, and spatially-resolved T2 distribution measurements, were applied during water flooding experiment and nitrogen driving water for decreasing retained water content of a high volatile bituminous coal sample. Distributions of fractures, pores and minerals were inversed based on micro-CT technology and the corresponding influences on retained water were discussed. The results showed that water saturation increasing process of total apertures, micro- and transition pores, meso-pores, macro-pores and fractures were increased by logarithmic relation with the increase of water flooding time. Nitrogen driving could basically decrease water saturation in macro-pores and fractures completely, and partly in meso-pores with a 50.11% decrease in water saturation. However, it can lead to increased water saturation by 6.89% in micro- and transition-pores. It is relatively easier to decrease retained water content when inlet pressure is increased during nitrogen driving because effective stress is decreased and connections between apertures are improved. The smaller mineral filling porosity, greater total porosity, and better connection of pores and fractures, the greater water content after water flooding. Retained water content of a sample with connected apertures is discharged effectively under nitrogen driving, while a sample that lacks connected apertures remains high in retained water content.

A new experimental method for measuring the three-phase relative permeability of oil, gas, and water

For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.

Complex conductivity of oil-contaminated clayey soils

Spectral induced polarization (SIP) is considered as a promising tool in environmental investigations. However, few works have done regarding the electrical signature of oil contamination of clayey soils upon induced polarization. Laboratory column experiments plus one sandbox experiment are conducted in this study to investigate the performances of the SIP method in oil-contaminated soils. First, a total of 12 soils are investigated to reveal the influences of water and soil properties on the saturation dependence of the complex conductivity below 100 Hz. Results show that the magnitude of the complex conductivity consistently decreases with decreasing water saturation for all soils samples. The saturation n and quadrature conductivity p exponents tend to increase slightly with increasing water salinity when using a linear conductivity model. The saturation exponent increases marginally with the cation exchange capacity (CEC) and the specific surface area (Ssp) while the quadrature conductivity exponent exhibits a relatively stronger dependence on both CEC and Ssp. For the low CEC soil samples (normally ≤10 meq/100 g), the quadrature conductivity exponent p correlates well with the saturation exponent n using the relationship p = n−1. SIP method is further applied in a sandbox experiment to estimate the saturation distribution and total volume of the oil. Results demonstrate that the SIP method has a great potential for mapping the organic contaminant plume and quantifying the oil volume.

Relative permeability estimates for Wolfcamp and Eagle Ford shale samples from oil, gas and condensate windows using adsorption-desorption measurements

Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate relative permeability of aqueous and hydrocarbon phase in shales by processing the low-pressure nitrogen adsorption-desorption isotherm measurements. The interpretation method is applied to 35 samples from various maturity windows of Eagle Ford and Wolfcamp shale formations. The method assumes that effective medium theory, percolation theory, and critical path analysis can quantify the biphasic fluid transport in shales.The relative permeability curves were estimated for samples collected from 100ft interval in Eagle Ford gas window, 30ft interval in Eagle Ford oil window, and 60ft interval in Wolfcamp condensate window. Although the samples exhibit large variations in organic content, pore connectivity, range of connected pore network, and pore complexity, the relative permeability curves estimated for these samples exhibit relatively similar trends. Samples from gas and oil windows were low temperature plasma ashed to study the effects of removal of organic matter on relative permeability and pore network characteristics. The relative permeability of aqueous phase decreases sharply with decrease in water saturation, whereas the relative permeability of hydrocarbon phase decreases at a relatively slow and constant rate with increase in water saturation. Relative permeability estimates for the shale samples explain the low water-cut during hydrocarbon production, absence of correlation between hydrocarbon production decline and the increase in water production, and the existence of permeability jail in shale reservoirs.

Geo-electrical Characterisation for CO2 Sequestration in Porous Media

Developing monitoring strategies for the detection and monitoring of possible CO2 leakage or migration from existing and anticipated storage media are important because they can provide an early warning of unplanned CO2 leakage from a storage site. While previous works have concentrated on silicate and carbonate porous media, this work explores geoelectrical techniques in basalt medium in a series of well-defined laboratory experiments. These were carried out to identify the key factors which affect geoelectrical monitoring technique of CO2 in porous media using low cost and efficient time domain reflectometry (TDR). The system has been set up for simultaneous measurement of the bulk electrical conductivity and bulk dielectric permittivity of CO2-water-porous media system in silica sand, basalt and limestone. Factors investigated include pH, pressure, temperature, salinity, salt type and the materials of the porous media. Results show that the bulk electrical conductivity and dielectric permittivity decrease as water saturation decreases. Noticeably, electrical conductivity and permittivity decrease due to the changes in water saturation and the relationship remains the highest in limestone except at the start of the experiment. Also, an increase in temperature, pressure and salinity tend to increase the bulk electrical conductivity (σb) and permittivity (eb) of the CO2-water-porous media system during the drainage experiment. On the other hand, pH and concentrations of different types of salt do not seem to have significant effect on the geoelectrical characteristics of the system. It was evident that Archie’s equation fit the experimental results well and the parameters obtained were in good agreement with those in the literatures. The regression shows a good reliability in the prediction of electrical properties during the monitoring process of CO2 sequestration.

Pore-scale modelling of relative permeability of cementitious materials using X-ray computed microtomography images

Permeability of cementitious materials is an important durability indicator. In practice, concrete is rarely saturated. Therefore, it is essential to study permeability of unsaturated cementitious materials. This paper presents an integrated modelling approach for estimating permeability of cementitious materials over the full range of saturation. An in-house code based on multiphase and single-phase lattice Boltzmann models is developed and used to simulate the moisture distribution and fluid flow in unsaturated cement paste with various curing ages, the 3D microstructures of which are obtained from X-ray micro-CT. The water permeability and gas permeability of partially saturated cement paste are then estimated. The results indicate with decreasing water saturation water permeability decreases while gas permeability increases. Additionally, the moisture distribution and permeability of unsaturated cement paste are strongly dependent on its microstructure. Moreover, there exists a unique relationship between permeability and effective porosity. The simulation results show good agreement with experimental data.

Numerical simulation and parameter analysis of NMR T2–D distributions of tight sandstone saturated with a gas–water two-phase fluid

Two-dimensional nuclear magnetic resonance (NMR) transverse relaxation time–diffusion coefficient (T2–D) distributions can simultaneously provide with pore-fluid parameters of the relaxation and the diffusion, making it possible to distinguish fluid types based on the differences in the two parameters. Hence, T2–D distributions are advantageous over one-dimensional T2 distributions for the identification of fluids because the T2 distributions of different fluids sometimes overlap. In this paper, we simulated NMR measurements with diffusion-editing pulse sequences in tight sandstone saturated with a gas–water two-phase fluid using the random-walk method, and the simulated echo trains were inverted to obtain the T2–D distributions. The effect of fluid saturation on the T2–D distributions of tight sandstone was analyzed, and we studied the effects of the observation parameters–echo spacing TE, magnetic field gradient G, and the group of echo spacing TE1–in diffusion-editing pulse sequences and data signal-to-noise ratios (SNRs) on T2–D distributions of tight sandstone with different gas saturations. The simulated results showed that the water signal in T2–D distributions of tight sandstone gradually moved to a lower diffusion coefficient and a shorter transverse relaxation time with decreasing water saturation, but the gas signal remained fixed in position. With increasing echo spacing TE or magnetic field gradient G, the gas signal in the T2–D distributions moved to shorter transverse relaxation times. The effects of echo spacing TE or magnetic field gradient G on the position of the water signal in the T2–D distributions can be ignored. T2–D distributions for the hybrid echo spacing TE1 group is much better at reflecting pore-fluid information than ones with the short echo spacing TE1 group or the long echo spacing TE1 group. When data SNRs are low, identifying pore fluids based on T2–D distributions is not reliable due to the partial overlap of the water and gas signals.

Two-phase Lattice Boltzmann modelling of streaming potentials: influence of the air–water interface on the electrokinetic coupling

The streaming potential phenomenon is an electrokinetic effect that occurs in porous media. It is characterized by an electrokinetic (EK) coefficient. The aim of this paper is to simulate the EK coefficient in unsaturated conditions using the Lattice Boltzmann method in a 2-D capillary channel. The multiphase flow is simulated with the model of Shan & Chen. The Poisson–Boltzmann equation is solved by implementing the model of Chai & Shi. The streaming potential response shows a non-monotonous behaviour due to the combination of the increase of charge density and decrease of flow velocity with decreasing water saturation. Using a ζ potential of −20 mV at the air–water interface, an enhancement of a factor 5–30 of the EK coefficient, compared to the saturated state, can be observed due to the positive charge excess at this interface which is magnified by the fluid velocity away from the rock surface. This enhancement is correlated to the fractioning of the bubbles, and to the dynamic state of these bubbles, moving or entrapped in the crevices of the channel.

Geomechanical, Hydraulic and Thermal Characteristics of Deep Oceanic Sandy Sediments Recovered during the Second Ulleung Basin Gas Hydrate Expedition

This study investigates the geomechanical, hydraulic and thermal characteristics of natural sandy sediments collected during the Ulleung Basin gas hydrate expedition 2, East Sea, offshore Korea. The studied sediment formation is considered as a potential target reservoir for natural gas production. The sediments contained silt, clay and sand fractions of 21%, 1.3% and 77.7%, respectively, as well as diatomaceous minerals with internal pores. The peak friction angle and critical state (or residual state) friction angle under drained conditions were ~26° and ~22°, respectively. There was minimal or no apparent cohesion intercept. Stress- and strain-dependent elastic moduli, such as tangential modulus and secant modulus, were identified. The sediment stiffness increased with increasing confining stress, but degraded with increasing strain regime. Variations in water permeability with water saturation were obtained by fitting experimental matric suction-water saturation data to the Maulem-van Genuchen model. A significant reduction in thermal conductivity (from ~1.4–1.6 to ~0.5–0.7 W·m−1·K−1) was observed when water saturation decreased from 100% to ~10%–20%. In addition, the electrical resistance increased quasi-linearly with decreasing water saturation. The geomechanical, hydraulic and thermal properties of the hydrate-free sediments reported herein can be used as the baseline when predicting properties and behavior of the sediments containing hydrates, and when the hydrates dissociate during gas production. The variations in thermal and hydraulic properties with changing water and gas saturation can be used to assess gas production rates from hydrate-bearing deposits. In addition, while depressurization of hydrate-bearing sediments inevitably causes deformation of sediments under drained conditions, the obtained strength and stiffness properties and stress-strain responses of the sedimentary formation under drained loading conditions can be effectively used to assess sediment responses to depressurization to ensure safe gas production operations in this potential target reservoir.

The two-phase flow IPTT method for measurement of nonwetting-wetting liquid interfacial areas at higher nonwetting saturations in natural porous media.

Interfacial areas between nonwetting-wetting (NW-W) liquids in natural porous media were measured using a modified version of the interfacial partitioning tracer test (IPTT) method that employed simultaneous two-phase flow conditions, which allowed measurement at NW saturations higher than trapped residual saturation. Measurements were conducted over a range of saturations for a well-sorted quartz sand under three wetting scenarios of primary drainage (PD), secondary imbibition (SI), and secondary drainage (SD). Limited sets of experiments were also conducted for a model glass-bead medium and for a soil. The measured interfacial areas were compared to interfacial areas measured using the standard IPTT method for liquid-liquid systems, which employs residual NW saturations. In addition, the theoretical maximum interfacial areas estimated from the measured data are compared to specific solid surface areas measured with the N2/BET method and estimated based on geometrical calculations for smooth spheres. Interfacial areas increase linearly with decreasing water saturation over the range of saturations employed. The maximum interfacial areas determined for the glass beads, which have no surface roughness, are 32±4 and 36±5 cm-1 for PD and SI cycles, respectively. The values are similar to the geometric specific solid surface area (31±2 cm-1) and the N2/BET solid surface area (28±2 cm-1). The maximum interfacial areas are 274±38, 235±27, and 581±160 cm-1 for the sand for PD, SI, and SD cycles, respectively, and ~7625 cm-1 for the soil for PD and SI. The maximum interfacial areas for the sand and soil are significantly larger than the estimated smooth-sphere specific solid surface areas (107±8 cm-1 and 152±8 cm-1, respectively), but much smaller than the N2/BET solid surface area (1387±92 cm-1 and 55224 cm-1, respectively). The NW-W interfacial areas measured with the two-phase flow method compare well to values measured using the standard IPTT method.

Transport of colloidal silica in unsaturated sand: Effect of charging properties of sand and silica particles

We have studied the transport of colloidal silica in various degrees of a water-saturated Toyoura sand column, because silica particles are widely used as catalyst carriers and abrasive agents, and their toxicity is reported recently. Since water-silica, water-sand, and air-water interfaces have pH-dependent negative charges, the magnitude of surface charge was controlled by changing the solution pH.The results show that, at high pH conditions (pH 7.4), the deposition of colloidal silica to the sand surface is interrupted and the silica concentration at the column outlet immediately reaches the input concentration in saturated conditions. In addition, the relative concentration of silica at the column outlet only slightly decreases to 0.9 with decreasing degrees of water saturation to 38%, because silica particles are trapped in straining regions in the soil pore and air-water interface.On the other hand, at pH 5 conditions (low pH), where sand and colloid have less charge, reduced repulsive forces result in colloidal silica attaching onto the sand in saturated conditions. The deposition amount of silica particles remarkably increases with decreasing degrees of water saturation to 37%, which is explained by more particles being retained in the sand column associated with the air-water interface.In conclusion, at higher pH, the mobility of silica particles is high, and the air-water interface is inactive for the deposition of silica. On the other hand, at low pH, the deposition amount increases with decreasing water saturation, and the particle transport is inhibited.

Impact of Pressure and Brine Salinity on Capillary Pressure-Water Saturation Relations in Geological CO2Sequestration

Capillary pressure-water saturation relations are required to explore the CO2/brine flows in deep saline aquifers including storage capacity, relative permeability of CO2/brine, and change to stiffness and volume. The study on capillary pressure-water saturation curves has been conducted through experimentation and theoretical models. The results show that as the pressure increases up to 12 MPa, (1) capillary pressure-water saturation curves shift to lower values at given water saturation, (2) after the drainage process, residual water saturation decreases, and (3) after the imbibition process, capillary CO2trapping increases. Capillary pressure-water saturation curves above 12 MPa appear to be similar because of relatively constant contact angle and interfacial tension. Also, as brine salinity increases from 1 M to 3 M NaCl, (1) capillary pressure-water saturation curves shift to lower capillary pressure, (2) residual water saturation decreases, and (3) capillary CO2trapping increases. The results show that pressure and brine salinity have an influence on the capillary pressure-water saturation curves. Also, the scaled capillary CO2entry pressure considering contact angle and interfacial tension is inconsistent with atmospheric conditions due to the lack of wettability information. Better exploration of wettability alteration is required to predict capillary pressure-water saturation curves at various conditions that are relevant to geological CO2sequestration.

Post - sedimentation influence on filtration capacity reservoir rock properties (Pur-Tazov oil\\gas-bearing area)

The processes of the second mineral formation (kaolinite, carbonates and micas) were identified during the post-sedimentation transformation studies in oil\\gas deposits. Besides, quartz regeneration, solid product destructive formation processes and hydrocarbon oxidation processes were -determined. Correlation analysis of the mineralogy and petrophysics data revealed the post-sedimentation influence factors on the reservoir properties of deposits. It should be noted that the second kaolinite composition increase results in water saturation and density decrease, porosity and, especially, permeability increase. Quartz regeneration and second mica formation deteriorate the reservoir properties or poorly influence them. The hydrocarbon decay and oxidation products, as well as secondary carbonate seal the void space, replace the soluble rock debris and sharply deteriorate the reservoir properties of oil andgas deposits.

Experimental Simulation of Gas Seepage Characteristics of a Low-Permeability Volcanic Rock Gas Reservoir Under Different Water Saturations

During the gas production process, the permeability of a low-permeability volcanic gas reservoir increases with decreasing water saturation. Additionally, at constant water saturation, the permeability generally increases with decreasing pore pressure if the water saturation is lower than 40%, and the permeability increases slightly with increasing pore pressure if the water saturation is higher than 40%. We undertook this research work in the Kalamay volcanic gas reservoir in the Junggar Basin of China because this gas reservoir has typical seepage characteristics and there are unknown low-permeability volcanic gas reservoirs. Therefore, to study the seepage characteristics of gas in a low-permeability volcanic gas reservoir at different water saturations, we designed experimental methods of measuring the permeability, saturation, and flow rate in the course of core gas displacement to examine the effects of water saturation on gas seepage during the gas production process. In the study, we performed simulation experiments on eight volcanic cores sampled from three wells in the research area and analyzed their gas seepage characteristics at different levels of water saturation. The results reveal that the gas permeability of water-bearing volcanic reservoirs with low permeability values depends mainly on water saturation and pore pressure. Regardless of the slippage effect on the gas, the permeability of the reservoirs depends largely on the degree of original water saturation. In other words, the degree of water saturation directly determines the seepage capability of gas in reservoirs. The critical value of water saturation in the low-permeability volcanic gas reservoirs may be defined as 40%. When the water saturation is higher than 40%, the permeability increases with increasing pore pressure but does not increase substantially. Under these conditions, the gas seepage shows the characteristics of liquid-phase seepage, the gas-water seepage relation is complex, and the resistance to gas seepage is large. All of these make development very difficult and ineffective. When the water saturation is lower than 40%, the permeability increases with decreasing pore pressure, and the seepage characteristics of the gas follow those of a single-phase gas. Under these conditions, the degree of water saturation only influences the permeability of the reservoir and has little impact on the seepage characteristics of the gas.

Influence of water pressure dynamics and fluid flow on the streaming‐potential response for unsaturated conditions

ABSTRACTStreaming‐potentials are produced by electrokinetic effects in relation to fluid flow and are used for geophysical prospecting. The aim of this study is to model streaming potential measurements for unsaturated conditions using an empirical approach. A conceptual model is applied to streaming potential measurements obtained from two drainage experiments in sand. The streaming potential data presented here show a non‐monotonous behaviour with increasing water saturation, following a pattern that cannot be predicted by existing models. A model involving quasi‐static and dynamic components is proposed to reproduce the streaming potential measurements. The dynamic component is based on the first time derivative of the driving pore pressure. The influence of this component is investigated with respect to fluid velocity, which is very different between the two experiments. The results demonstrate that the dynamic component is predominant at the onset of drainage in experiments with the slowest water flow. On the other hand, its influence appears to vanish with increasing drainage velocity. Our results suggest that fluid flow and water distribution at the pore scale have an important influence on the streaming potential response for unsaturated conditions. We propose to explain this specific streaming potential response in terms of the behaviour of both rock/water interface and water/air interfaces created during desaturation processes. The water/air interfaces are negatively charged, as also observed in the case of water/rock interfaces. Both the surface area and the flow velocity across these interfaces are thought to contribute to the non‐monotonous behaviour of the streaming potential coefficient as well as the variations in its amplitude. The non‐monotonous behaviour of air/water interfaces created during the flow was highlighted as it was measured and modelled by studies published in the literature. The streaming potential coefficient can increase to about 10 to 40 when water saturation decreases. Such an increase is possible if the amount of water/air interfaces is increased in sufficient amount, which can be the case.

Hysteretic trapping and relative permeability of CO2 in sandstone at reservoir conditions

Hysteretic nonwetting phase trapping behavior is predicted to be a significant factor determining long term immobilization of injected CO2. This paper presents results from an experimental investigation of hysteresis in residual trapping and relative permeability of CO2 in a CO2/water system at 50°C and 9MPa in a Berea sandstone core. Carbon dioxide saturation data were collected using the steady-state method in a horizontal core-flooding apparatus with X-ray computed tomography. Three flooding cycles were completed at a constant total volumetric flow rate by incrementally increasing and decreasing the fractional flow rates of supercritical CO2 and water. The fractional flow rates were chosen such that the maximum CO2 saturation of each cycle was greater than that of the previous cycle. During the injection stage of a cycle, CO2 displaced water in a wetting-phase drainage process (water saturation decrease). Following injection, water displaced CO2 in a wetting-phase imbibition process (water saturation increase). The fractional flow of CO2 was then increased during the next cycle. Results showed the CO2 saturations trapped during wetting-phase imbibition increased with the maximum CO2 saturations reached during each cycle. The residually trapped CO2 saturation is a hysteretic function, depending on the maximum saturation reached by the core before imbibition. A linear model with coefficient 0.5 describes the nonwetting trapping relationship. The experimental relative permeability data for CO2 fit a single bounding primary drainage curve while CO2 saturations increased, but followed three different scanning curves during wetting-phase imbibition. The CO2 relative permeability data can be fit by making a minor modification in the Van Genuchten–Burdine relative permeability data to account for hysteresis.

Well injectivity during CO2 storage operations in deep saline aquifers—Part 1: Experimental investigation of drying effects, salt precipitation and capillary forces

Carbon Capture and Storage (CCS) is a technique than can potentially limit the accumulation of greenhouse gases in the atmosphere. Well injectivity issues are of importance for CCS because the gas injection rate must be maintained at a high level (a million tonnes of CO2 per year and per site) during the industrial operation period (30–40 years). The risk of altered permeability must therefore be determined in order to guarantee the sustainability and the security of the CO2 geological storage. Injection of dry gas in deep saline aquifers might lead to near wellbore drying and salt precipitation. The solid salt might then reduce the rock permeability by clogging pores or by pore throat restriction. The objective of this paper is to present new experimental results on the drying of rocks induced by continuous injection of large amount of dry gas (N2). The main goal of the study was to understand and model the physical processes that govern the decrease in water saturation in reservoir rocks.Two types of sandstone were used to study slow and fast drying rates and capillary effects on drying. The experimental results evince the main physical parameters that control the key mechanisms. In a companion paper in this issue (André et al., 2013), we show that the continuous approach in the context of a compositional two-phase flow model can fairly well predict the saturation evolution in the near wellbore and the alteration in permeability due to salt precipitation.

Does the reactive surface area of sandstone depend on water saturation?—The role of reactive-transport in water film

To investigate how mineral–water reactive surface area changes depending on water saturation, flow-through dissolution experiments were performed using a sandstone core at various water saturations. Fontainebleau sandstone with an open porosity of 6.3%, consisting of ∼100% quartz, was used. The water saturation of the core was adjusted to 0%, 51%, or 100%, and at each saturation, water was infiltrated into the core at a constant pressure. The experimental results showed that the total amount of dissolved Si did not change with decreasing water saturation. It can be therefore concluded that virtually all of the mineral surfaces were wetted with water film and allowed the progression of dissolution; i.e., the reactive surface area was not affected by water saturation despite the presence of air in the pores. The results also suggested that the flushing rate of dissolved Si from the interior of the water film to the exterior was fast enough to keep the Si concentration in the film sufficiently lower than the equilibrium concentration of quartz. We derived a reactive-transport model describing dissolution and diffusion in water film. The model shows that the solute concentration in a film is a function of the film thickness, diffusion length, dissolution rate of the mineral, equilibrium concentration, and roughness factor. As for the Fontainebleau sandstone, film thicknesses of 7–18nm and diffusion lengths of 300–600μm were estimated. The reactive-transport calculation confirmed that the overall dissolution rate of our sandstone sample was almost unaffected by water saturation, owing to the high flushing efficiency of dissolved Si in water film, which agrees with the experimental result. Application of the model allows us to evaluate whether the reactive surface area and the dissolution rate change with water saturation for a given rock of interest.

Drainage of Capillary-Trapped Oil by an Immiscible Gas: Impact of Transient and Steady-State Water Displacement on Three-Phase Oil Permeability

In a previous paper (Dehghanpour et al., Phys Rev E 83:065302, 2011a), we showed that relative permeability of mobilized oil, \(k_\mathrm{ro}\), measured during tertiary gravity drainage, is significantly higher than that of the same oil saturation in other tests where oil is initially a continuous phase. We also showed that tertiary \(k_\mathrm{ro}\) strongly correlates to both water saturation, \(S_\mathrm{w}\), water flux (water relative permeability), \(k_\mathrm{rw}\), and the change in water saturation with time, \(\mathrm{d}S_\mathrm{w}/\mathrm{d}t\). To develop a model and understanding of the enhanced oil transport, identifying which of these parameters (\(S_\mathrm{w},\,k_{\mathrm{rw}}\), or \(\mathrm{d}S_\mathrm{w}/\mathrm{d}t\)) plays the controlling role is necessary, but in the previous experiments these could not be deconvolved. To answer the remaining question, we conduct specific three-phase displacement experiments in which \(k_{\mathrm{rw}}\) is controlled by applying a fixed water influx, and \(S_\mathrm{w}\) develops naturally. We obtain \(k_{\mathrm{ro}}\) by using the saturation data measured in time and space. The results suggest that steady-state water influx, in contrast to transient water displacement, does not enhance \(k_{\mathrm{ro}}\). Instead, reducing water influx rate results in excess oil flow. Furthermore, according to our pore scale hydraulic conductivity calculations, viscous coupling and fluid positioning do not sufficiently explain the observed correlation between \(k_{\mathrm{ro}}\) and \(S_{\mathrm{w}}\). We conclude that tertiary \(k_{\mathrm{ro}}\) is controlled by the oil mobilization rate, which in turn is linked to the rate of water saturation decrease with time, \(\mathrm{d}S_\mathrm{w}/\mathrm{d}t\). Finally, we develop a simple model which relates tertiary \(k_{\mathrm{ro}}\) to transient two-phase gas/water relative permeability.

Pore-Scale Modeling of Waterflooding in Mixed-Wet-Rock Images: Effects of Initial Saturation and Wettability

Summary We simulate transient behavior of viscous- and capillary-dominated water invasion at mixed-wet conditions directly in scanning-electron-microscope (SEM) images of Bentheim sandstone by treating the pore spaces as cross sections of straight tubes. Initial conditions are established by drainage and wettability alteration. Constant rate or differential pressure is imposed along the tube bundle. The phase pressures vary with positions along the tube length but remain unique in each cross section, consistent with 1D core-scale models. This leads to a nonlinear system of equations that are solved for the interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by a semianalytical model that is based on free-energy minimization. The fluid conductances are estimated by newly derived explicit expressions that are shown to be in agreement with numerical computations performed directly on the cross-sectional fluid configurations. An SEM image of Bentheim sandstone is taken as input to the developed model for simulating the evolution of saturation profiles during waterfloods for different flow rates and several mixed-wet conditions, which are established with various initial water saturations and contact angles. It is demonstrated that the simulated saturation profiles depend strongly on initial water saturation at mixed-wet conditions. The saturation profiles exhibit increasingly gradual behavior in time as the contact angle, defined on the oil-wet solid surfaces, increases or the initial water saturation decreases. Front menisci associated with positive capillary pressures promote oil displacement by water, whereas for large and negative capillary pressures at small flow rates, oil displaces water because the associated front menisci retract. This results in the development of pronounced gradual saturation fronts at mixed-wet conditions. The waterfloods simulated at conditions established with a large initial water saturation and small contact angle on the oil-wet solid surfaces exhibit sharp Buckley-Leverett saturation profiles for high flow rates because the capillary pressure is small and less important. The shape of the saturation profiles is interpreted on the basis of the simulated capillary pressure curves and the corresponding fluid configurations occurring in the rock image.