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Recent developments in Radio Frequency (800 MHz–1000 MHz) Identification (RFID) devices suggest that it is possible to use them for wireless laboratory measurements of the dielectric coefficients (or compositions) of fluid mixtures with possible spin-off for their use in the petroleum engineering practice. The advantage of RFID devices is their small size ( 0.095 × 0.008 × 0.001 m 3 ), the developments to make them increasingly smaller and that they do not require the use of leak prone connecting cables. RFID measures the response of a sample volume of interest irradiated by a radio frequency electromagnetic (EM) wave. The response can be expressed in terms of various response functions, e.g. two scattering functions (S 11 and S 21 ) or the minimum irradiated power (P min ). The response functions can be measured using a state-of-the-art RFID device (CISC RFID Xplorer-200), which operates in the range between 800 and 1000 MHz. The effect of the dielectric coefficient on the RFID response was tested by placing the RFID tag in different media with various dielectric coefficients ε ranging from 1 to 80. The overall purpose is to develop a work-flow to relate the response functions obtained with RFID technology to the dielectric coefficient and thus the composition of fluid mixtures in which an RFID tag can be immersed. An application is to measure fluid compositions during a spontaneous imbibition experiment in an Amott-cell. As an intermediate step we measure the composition dependence of the partial molar volume of diethyl ether (DEE) in brine and the partial molar volume of DEE in oil by using an Anton Paar density meter. The relation between the dielectric coefficients and the volume fraction can be obtained with the Böttcher mixing rule. The DEE volume fraction range of interest is 0–8% volume fraction in the aqueous solution whereas DEE volume fraction range of interest is 0–100% volume fraction in oleic solutions. For better understanding of the measurement results, we used COMSOL™ simulations, which show that the response functions depend on the dielectric coefficient in a vessel of appropriate dimensions filled with a fluid of choice. The measurements show that the minimum power at the tag position P m i n is the preferred response function and that the sensitivity of P m i n was highest at 915 and 868 MHz for aqueous (8.547 × 10 − 6 ) and oleic (1.905 × 10 − 4 ) solutions respectively. The measurement error is of the same order of magnitude as the errors mentioned above (Hon, 1989) ensuing from evaporation of DEE during the preparation of the calibration fluids or the approximate nature of the Böttcher mixing rule. We conclude that it is possible to use RFID technology for contact-less measurements of the compositions of fluids in imbibition experiments. [ABSTRACT FROM AUTHOR]

Foam generated with a surfactant solution and nitrogen is used for oil recovery, acid diversion and aquifer remediation. In laboratory experiments, the foam mobility is expressed in terms of the pressure drop across the porous medium and is related to many physical processes. There is lack of data that relate the pressure drop to a combination of three or more variables simultaneously. This paper investigates the steady state pressure drop for a combination of six variables, viz., permeability, surfactant concentration, pH, salinity, surfactant solution velocity and gas velocity. Fourteen pressure drop histories were measured for an Alpha Olefin Sulphonate solution before and after the injection of nitrogen gas across the unconsolidated sandpacks of two median grain sizes and across a Bentheimer consolidated core. Our data set was combined with data sets from the literature leading to 157 data points. Symbolic regression was applied to the entire data set to produce a number of analytical expressions describing the interactive effect of the variables without prior knowledge of an underlying physical process. A simple model with only one fitting parameter was selected to compare with the experimental data. The slope between the observed pressure drop and the predicted pressure drop turns out to be 0.85±0.03. A sensitivity analysis of the chosen model shows that the variables affecting the predicted pressure drop, in order of importance, are permeability, salinity and surfactant solution velocity. The precision of the model parameter was determined by a bootstrap method. The pressure drop from our data set and one specific data set from the literature show significant deviation with respect to the pressure drop obtained from the regression equation. Possible reasons are that the specific data set from the literature uses mixtures of surfactants and that our data set is confined to conditions that lead to low pressure drops. The purpose of the data driven model applied to experimental data is only to improve the models based on physical processes, i.e., mechanistic models. In addition the data driven model can indicate the variable spaces for which more experiments are needed. [ABSTRACT FROM AUTHOR]

An improved version of the manometric apparatus and its procedures for measuring excess sorption of supercritical carbon dioxide are presented in detail with a comprehensive error analysis. An improved manometric apparatus is necessary for accurate excess sorption measurements with supercritical carbon dioxide due to the difficulties associated with the high sensitivity of density for pressure and temperature changes. The accuracy of the apparatus is validated by a duplicate measurement and a comparison with literature data. Excess sorption and desorption of CO2 on Filtrasorb 400 at 318.11 K up to 17 069 mole/m3 (15.474 MPa) were selected for this validation. The measured excess sorption maximums are 7.79±0.04 mole/kg at 2253 mole/m3 for the first sorption isotherm and 7.91±0.05 mole/kg at 2670 mole/m3 for its subsequent desorption isotherm. The sorption and desorption peaks of the duplicate experiment are 7.92±0.04 mole/kg at 2303 mole/m3 and 8.10±0.05 mole/kg at 2879 mole/m3, respectively. Both data sets show desorption data being higher than the sorption data of the same data set. The maximum discrepancy between the desorption and sorption isotherms of one data set is 0.15 mole/kg. The discrepancy between the two excess sorption isotherms is 0.12 mole/kg or less. The a priori error of the excess sorption measurements is between 0.02 and 0.06 mole/kg. The error due to He contamination is between 0.01 and 0.05 mole/kg. The difference between the a priori uncertainty and the observed maximum discrepancies is considered to be acceptable. The sorption isotherms show identical qualitative behavior as data in the literature. The quantitative behavior is similar but the peak height and the linear decrease in excess sorption at high gas densities are 10% higher. A plot of the excess sorption versus the density can be used to obtain the sorbed phase density and the specific micropore volume. These sorbed phase densities are in excellent agreement with the data in the literature. Furthermore, the excess sorption data scaled to this specific micropore volume in this work and in the literature collapse on a single curve when plotted versus gas density. [ABSTRACT FROM AUTHOR]

This paper is motivated by the study of the sorption processes in the coal. They are modeled by a nonlinear degenerate pseudoparabolic equation for stress-enhanced diffusion of carbon dioxide (CO2) in coal, ∂tφ = ∂x {D(φ) ∂xφ+ D(φ)φ/ B ∂x (e-mφ∂tφ}, where B,m are positive constants and the diffusion coefficient D(φ) has a small value when the CO2 volume fraction φ is 0 ≤ φ < φc, representative of coal in the glass state and orders of magnitude higher value for φ > φc, when coal is in the rubber-like state. These types of equations arise in a number of cases when nonequilibrium thermodynamics or extended nonequilibrium thermodynamics is used to compute the flux. For this equation, existence of the travelling wave--type solutions was extensively studied. Nevertheless, the existence seems to be known only for a sufficiently short time. We use the corresponding entropy functional in order to get existence, for any time interval, of an appropriate weak solution with square integrable first derivatives and satisfying uniform L∞-bounds. Due to the degeneracy, we obtain square integrability of the mixed second order derivative only in the region where the concentration φ is strictly positive. In obtaining the existence result it was crucial to have the regularized entropy as unknown for the approximate problem and not the original unknown (the concentration). [ABSTRACT FROM AUTHOR]

Abstract: The behavior of underground coal fires is determined by a complex interaction between geomechanical effects, related overburden permeability and reactive natural convection. We are building on previous work, where natural convection flow and heat flow in response of a given temperature of the burning coal face were considered. A two-dimensional model is developed, combining both geomechanical and reactive flow effects. For an initial uniform permeability field the reactive free convection model is used to obtain temperature distribution, which is used in a compaction model, from which a new permeability distribution is derived. This final permeability distribution is used in the reactive free convection model to obtain the velocity distribution, the oxygen concentration profile and the temperature distribution. The temperature profile and oxygen concentration profile, within the permeability range of interest, depend on the permeability distribution, but is relatively insensitive to the average permeability value. However, the oxygen consumption by combustion is approximately proportional to the square root of the average permeability. The rubble zone and the fault closest to the burning coal front are the main path ways to a deep coal fire, as these highly permeable zones act respectively as an air intake and exhaust under practical heterogeneous permeability conditions. For shallow coal fires the main inflow of oxygen is through faults and overburden, while heat loss effects are more important than for deep coal fires. [Copyright &y& Elsevier]

Abstract: Carbon dioxide injection into coal layers serves the dual purpose to enhance coal bed methane production (ECBM) and to store CO2. The efficiency of this process is expected to be much higher if water is the non-wetting phase in the coal–water–gas system. Therefore, contact angles in the coal–water–CO2 system have been measured using the captive bubble technique in the pressure range between atmospheric pressure and 141 bar at a temperature of 45 °C. At atmospheric pressure the contact angle of a shrinking CO2 droplet increases with time, but stays below 90°. At higher pressures (>2.6 bar) the contact angle increases beyond 90°. The pressure dependence of the contact can be represented by . The exceptional behavior at atmospheric pressure is possibly related to the stability of water patches on the coal surface. It is concluded that water is the non-wetting phase in this coal–water–CO2 system. [Copyright &y& Elsevier]

1D water oil displacement in porous media is usually described by the Buckley-Leverett equation or the Rapoport-Leas equation when capillary diffusion is included. The rectilinear geometry is not representative for near well oil displacement problems. It is therefore of interest to describe the radially symmetric Buckley-Leverett or Rapoport-Leas equation in cylindrical geometry (radial Buckley-Leverett problem). We can show that under appropriate conditions, one can apply a similarity transformation (r , t) → η = r 2 / (2 t) that reduces the PDE in radial geometry to an ODE, even when capillary diffusion is included (as opposed to the situation in the rectilinear geometry (Yortsos, Y.C. (Phys. Fluids 30(10),2928–2935 1987)). We consider two cases (1) where the capillary diffusion is independent of the saturation and (2) where the capillary diffusion is dependent on the saturation. It turns out that the solution with a constant capillary diffusion coefficient is fundamentally different from the solution with saturation-dependent capillary diffusion. Our analytical approach allows us to observe the following conspicuous difference in the behavior of the dispersed front, where we obtain a smoothly dispersed front in the constant diffusion case and a power-law behavior around the front for a saturation-dependent capillary diffusion. We compare the numerical solution of the initial value problem for the case of saturation-dependent capillary diffusion obtained with a finite element software package to a partially analytical solution of the problem in terms of the similarity variable η. [ABSTRACT FROM AUTHOR]

Abstract: Shale gas resources are globally abundant, and the development of these resources can increase CH4 production. It is of interest to study the possibility of enhancing CH4 production by CO2 injection (enhanced gas recovery—EGR). Some studies indicate that, in shale, five molecules of CO2 can be stored for every molecule of CH4 produced. The technical feasibility of enhanced gas recovery (EGR) needs to be investigated in more detail. The amount of extracted natural gas from shale has increased rapidly over the past decade. A typical shale gas reservoir combines an organic-rich deposition with extremely low matrix permeability. One important parameter in assessing the technical viability of (enhanced) production of shale gas is the sorption capacity. Our focus is on the sorption of CH4 and CO2. Therefore, we have chosen to use the manometric method to measure the excess sorption isotherms of CO2 at 318K and of CH4 at 308, 318 and 336K and at pressures up to 105bar on Belgium dry black shale from a depth of 745m. The shale was obtained from the former coal mine in Zolder in the Campina Basin (North Belgium), which contains Westphalian coal and coal associated sediments of Northwest European origin. We derive the equations for excess sorption in the manometric setup. Only a few measurements have been reported in the literature for high-pressure gas sorption on shales, and interest is largely focused on shales occurring outside Europe. The excess sorption isotherm shows an initial increase to a maximum value of 0.175±0.004mmol/gram for CO2 and then starts to decrease until it becomes zero at 82bar and subsequently the excess sorption becomes negative. Similar behaviour was also observed for other shales and coal reported in the literature. The experiments on CH4 show, as expected, decreasing sorption for increasing temperature. We apply an error analysis based on the Monte Carlo simulation. It shows that the error is increasing with increasing pressure, but that the manometric setup can be used to determine the sorption capacity of CO2 and CH4 on the black shale with sufficient accuracy. [Copyright &y& Elsevier]

Abstract: Various options are considered to reduce CO2 emissions when utilizing deep coal by applying underground coal gasification (UCG), i.e., in combination with carbonation of synthetic minerals (CaO), conventional UCG followed by ex-situ separation of CO2 and upgrading the product gas using naturally occurring minerals (wollastonite). A chemical equilibrium model was used to analyze the effect of process parameters on product composition and use it for an exergy analysis. The result is presented in terms of theoretical (ideal unit operations), practical (state of the art technology), and zero-emission (applying current CO2 capture and sequestration technology (CCS) to all sources of CO2 emission) recovery factors. The results show that underground gasification of deep coal can optimally extract 52–68% of the coal chemical exergy, but zero-emission extraction gives a negative recovery indicating that it is not practical with current state of the art CCS technology. Using in-situ CaO, which will enhance the H2 production, is theoretically feasible with a recovery factor around 80%, but is not exergetically feasible with the current state of technology. Ex-situ upgrading of the conventional UCG product gas with wollastonite is exergetically feasible for both practical and zero-emission cases according to the equilibrium model. [Copyright &y& Elsevier]

Abstract: In Enhanced Coal Bed Methane (ECBM) usually CO2 mixtures containing impurities such as NOx, etc., are injected in the coal layer. This paper investigates the adequacy of different Equations of State (EoS) for the determination of adsorption of gas mixtures in a manometric set up. We investigate the viability of these EoS by performing experiments in a reference cell and an empty sample cell at a constant temperature of 318.15K. From these measurements we derive the volume ratio of these cells. We used a variety of EoS and mixing rules to validate whether they can be applied, i.e., lead to the correct volume ratio. It is shown that for a He rich mixture (98% He, 1% O2 and 1% NO2) it is possible to use the McCarty EoS for pure helium for this purpose but that none of the other EoS, including mixing rules, give acceptable results. For a CO2 rich mixture (97% CO2, 1% He, 1% O2 and 1% NO2) none of the investigated EoS and mixing rules can be applied. Therefore, we present an experimental stepwise procedure based on the volume ratio measurements, to obtain correct density values with an error between 0.033% for high densities to 0.85% for low densities. [Copyright &y& Elsevier]

It has been estimated that 17% of the recovered hydrocarbon exergy in oil fields [ 1 ] is spent on fluid handling and recovery costs. Therefore, improving the efficiency of oil production can give an some contribution to more efficient energy usage and therefore minimizing to some extent the carbon footprint. By way of example we present in this paper a work-flow, which can serve as a template for computing the fluid handling and recovery costs for natural polymer (Guar-Arabic Gum) flooding. The main contributors to the exergy investment in an Exergy Return on Exergy Investment analysis (ERoEI) are, the fluid circulation costs, the steel costs of the tubing and casing and to some degree the drilling costs. The main contributor to the exergy gain is the exergy of the produced oil. The fluid circulation costs represent the largest exergy investment and usually approximately accounts for 80% of the exergy used for the recovery of oil. For quantifying the circulation costs, the paper uses a 1-D displacement model of polymer flooding of oil to compare the enhanced oil recovery (EOR) history for three scenarios, i.e., (1) water injection, (2) natural-polymer water injection and (3) natural-polymer slug injection. The advantage of a 1-D model is that it allows multiple comparisons of many scenario's avoiding time consuming simulations but this goes at the expense of ignoring 3-D effects. The 1-D model can be extended to a 2-D or 3-D model, which makes it possible to include the improvement of vertical and areal sweep-efficiency. A numerical solution of the EOR model is obtained with COMSOL. We analyze the exergy balance of viscosified water, e.g., with natural-polymer. A comparison as to the displacement efficiency is made between the three scenarios, viz., water, Guar-Arabic gum, and slug injection. The viscosity behavior of Guar-Arabic gum is obtained from laboratory data. It is argued that an ERoEI analysis, which is used on its own or complementary to an economic analysis, can be used to show the advantage of using Guar-Arabic gum slugs with respect to permanent polymer-injection to enhance the oil recovery. Moreover, the analysis shows that at the end of the project, the concept of exergy-zero recovery time or zero-time marks, for each scenario the termination point, i.e., when the circulation exergy costs (exergy investment) become equal to the recovery exergy (exergy return), and thus recovery should be abandoned. For the conditions considered a single polymer injection displacement leads to optimal results. • Using a 1-D model of natural-polymer displacement it is possible to analyse the Exergy Return on Exergy Investment (ERoEI). • The investment costs are frequently mainly due to circulation costs (%80) of the exergy used for the recovery of oil. • A small rock permeability leads to high circulation costs, thus higher invested exergy costs. • The abandonment time occurs before the circulation exergy costs become equal to the recovery exergy costs. • A minimum exergy cost corresponds to minimum greenhouse gas emission. [ABSTRACT FROM AUTHOR]

In this paper, we assess and model new strategies for integration of geothermal energy with gas production in the Oude Leede Gas Field in the Netherlands. We investigate the injection of cooled geothermal water into a gas field located just few kilometers away from the geothermal reservoir in the Netherlands. This synergy type can be considered for economic natural gas production from a gas field in the proximity of a geothermal doublet project and improved energy production in the geothermal reservoir. A 3-D model including a gas trapping mechanism was built to study the possible production potential of the gas field. Water flooding compensates pressure loss by reducing the pore space, however it complicates the process by introducing trapped gas. We studied the effect of injection rate, permeability, saturation condition before flooding and reservoir pressure on the ultimate gas recovery and the residual trapped gas saturation. Injecting water will increase the ultimate recovery factor for higher abandonment pressure. Higher water injection rates will keep the reservoir pressure up, increase the trapped gas saturation, and hence reduce the maximum recovery. The presence of heterogeneity and capillary forces has minor effects on the gas recovery factor. The exergy recovery factor of a water injection process is higher than a gas compression process due to the large amounts of energy required for compression. Considering net present value (NPV) analysis for a higher abandonment pressure, water injection is economically preferable, however not feasible. At a lower abandonment pressure, natural gas depletion can easily compete with the water injection process due to the higher costs of water injection and drilling. • The exergy recovery factor of a water injection process is higher than a gas compression process due to the large amounts of energy for compression. • Considering NPV analysis for a higher abandonment pressure, water injection is economically preferable, however not feasible. [ABSTRACT FROM AUTHOR]

Recent studies have shown that by coupling the underground coal gasification (UCG) with the carbon capture and storage (CCS), the coal energy can be economically extracted with a low carbon footprint. To investigate the effect of UCG and CCS process parameters on the feasibility of the UCG-CCS process, we utilize a validated mathematical model, previously published by the same authors, that can predict the composition of the UCG product, temperature profile, and coal conversion rate for alternating injection of air and steam for unmineable deep thin coal layers. We use the results of the model to conduct an energy and exergy analysis of the UCG process. We study the effect of various process parameters on the efficiency of the UCG process, the zero-emission recovery factor of coal, and the total CO 2 emission of the process. Moreover, we compare the alternating injection of air/steam with the injection of an air and steam mixture. Exergy analysis shows that the alternating injection of air/steam describes a practical process for UCG at low pressure. However, injecting a mixture of steam and oxygen results in a practical recovery factor of coal higher than the alternating injection process. Additionally, we show that the zero-emission conversion of unmineable deep thin coal resources in a coupled UCG-CCS process, that is not practical with the current state of technology, can be realized by increasing the energy efficiency of the carbon dioxide capture process. [ABSTRACT FROM AUTHOR]

Recent successful low-pressure underground coal gasification pilot experiments that use alternating injection of air (oxygen) and steam have shown potential in large scale hydrogen production. This paper extends an existing steady state model to a transient model that can describe an alternating injection of air and steam for deep thin coal layers. The model includes transient heat conduction, where the produced heat during the air injection stage is stored in the coal and surrounding strata. The stored heat is used in the endothermic gasification reactions during the steam injection. The results show that product composition and temperature oscillation can be predicted with a reasonable accuracy. The stored heat can deliver additional energy that can maintain the gasification during the steam injection period for a limited time. During the steam injection cycle, at low pressure the volumetric flow and the hydrogen content of the product gas are both high, but at higher pressures while the hydrogen composition is still high the coal conversion decreases considerably. The results confirm that the alternating injection of air/steam describes a practical process for UCG at low pressure. However, at high pressure, injecting a mixture of steam and oxygen instead of alternating injection of oxygen/steam results in a higher coal conversion rate, with a final product that contains higher carbon content. [ABSTRACT FROM AUTHOR]

Volatile oil recovery through air injection is a promising method for highly heterogeneous low permeability reservoirs. Thermal effects due to oxidation reaction, vaporization/condensation and flue gas drive are the most important mechanisms for light oil recovery by medium pressure air injection. To gather evidence for this claim, we performed ramped temperature experiments with consolidated cores filled with hexadecane injecting either air or nitrogen at different injection rates at medium pressures. The experiments show that oxygen is removed from the injected air through physical and chemical sorption by the hydrocarbon at low temperatures. Most of the bonded oxygen is released later at higher temperatures and reacts to form carbon oxides. The amount of oil burned in the air injection process relative to the amount of oil recovered increased from 2% at 10 bar to 18% at 30 bar, and again decreased to 5% at 45 bar and 3% at 70 bar. This trend was predicted theoretically in an earlier study of the medium temperature oxidation process. [ABSTRACT FROM AUTHOR]

We formulate a mathematical model for one dimensional flow with chemical reactions resulting from injection of air into a porous medium initially filled with gas, water and volatile oil. Our goal is to investigate the effect of water and steam on oil recovery, and we do so for a medium pressure air injection process. We show that, when the boiling point of the volatile oil is below or slightly above the boiling point of water, the hot steam region moves upstream of the medium temperature oxidation (MTO) wave (where oil vaporization and combustion occur), while the volatile oil and steam condense at the same location; it leads to considerable improvement of oil recovery by the MTO wave. Remarkably, the recovery curves (recovery fraction vs. time) depend weakly on the initial water and light oil saturations. If the volatile oil boiling point is much higher than the boiling point of water, the steam region moves downstream of the MTO wave. In this case the water effect on recovery is weaker and becomes negative for high water saturations. Numerical calculations suggest the existence of an oil boiling point at which a bifurcation occurs that separates solutions with the steam region upstream or downstream of the combustion zone. [ABSTRACT FROM AUTHOR]

Optimal storage of carbon dioxide (CO 2 ) in aquifers requires dissolution in the aqueous phase. Nevertheless, transfer of CO 2 from the gas phase to the aqueous phase would be slow if it were only driven by diffusion. Dissolution of CO 2 in water forms a mixture that is denser than the original water or brine. This causes a local density increase, which induces natural convection currents accelerating the rate of CO 2 dissolution. The same mechanism also applies to carbon dioxide enhanced oil recovery. This study investigates a set of high pressure visual experiments, based on the Schlieren technique, in which we observe the effect of gravity-induced fingers when sub- and super-critical CO 2 at in situ pressures and temperatures is brought above the liquid, i.e., water, brine or oil. A short but comprehensive description of the Schlieren set-up and the transparent pressure cell is presented. The Schlieren set-up is capable of visualizing instabilities in natural convection flows; a drawback is that it can only be practically applied in bulk flow, i.e., in the absence of a porous medium. All the same many features that occur in a porous medium also occur in bulk, e.g., unstable gravity fingering. The experiments show that natural convection currents are weakest in highly concentrated brine (25 w/w% NaCl solution) and strongest in oil, due to the higher and lower density contrasts respectively. Therefore, the set-up can screen aqueous salt solutions or oil for the relative importance of natural convection flows. The Schlieren pattern consists of a dark region near the equator and a lighter region below it. The dark region indicates a region where the refractive index increases downward, either due to the presence of a gas liquid interface, or due to the thin diffusion layer. The experiments demonstrate the initiation and development of the gravity induced fingers. [ABSTRACT FROM AUTHOR]

Abstract: In response to increasing use of the subsurface, there is a need to modernise policies on sustainable use of the subsurface. This holds in particular for the densely populated Netherlands. We aimed to analyse current practice of subsurface management and the associated pressure points and to establish a conceptual overview of the technical issues related to sustainable management of the subsurface. Case studies on the exploitation of subsurface resources (including spatial use of the subsurface) were analysed, examining social relevance, environmental impact, pressure points and management solutions. The case studies ranged from constructing underground garages to geothermal exploitation. The following issues were identified for the technological/scientific aspects: site investigation, suitability, risk assessment, monitoring and measures in the event of failure. Additionally, the following general issues were identified for the administrative aspects: spatial planning, option assessment, precaution, transparency, responsibility and liability. These issues were explored on their technological implications within the framework of sustainable management of the subsurface. This resulted into the following key aspects: (1) sustainability assessment, (2) dealing with uncertainty and (3) policy instruments and governance. For all three aspects, different options were identified which might have a legal, economic or ethical background. The technological implications of these backgrounds have been identified. A set of recommendations for sustainable management of the subsurface resources (incl. space) was established: (1) management should be driven by scarcity, (2) always implement closed loop monitoring when the subsurface activities are high-risk, (3) when dealing with unknown features and heterogeneity, apply the precautionary principle, (4) responsibility and liability for damage must be set out in legislation and (5) sustainability should be incorporated in all relevant legislation and not only in environmental legislation. Other aspects to be considered are the reversibility of the impacts from subsurface activities and the abandonment of installations. [Copyright &y& Elsevier]

Carbon dioxide injected in an aquifer rises quickly to the top of the reservoir and forms a gas cap from where it diffuses into the underlying water layer. Transfer of the CO2 to the aqueous phase below is enhanced due to the high density of the carbon dioxide containing aqueous phase. This paper investigates the behavior of the diffusive interface in an enclosed space in which initially the upper part is filled with pure carbon dioxide and the lower part with liquid. Our analysis differs from a conventional analysis as we take the movement of the diffusive interface due to mass transfer and the composition dependent viscosity in the aqueous phase into account. The same formalism can also be used to describe the situation when an oil layer is underlying the gas cap. Therefore we prefer to call the lower phase the liquid phase. In this paper we include these two effects into the stability analysis of a diffusive interface between CO2 and a liquid in the gravity field. We identify the relevant bifurcation parameter as q = [variant_greek_epsilon]Ra, where [variant_greek_epsilon] is the width of the interface. This implies the (well known) scaling of the critical time ∼Ra-2 and wavelength ∼Ra-1(The critical time tc and critical wavelength kc are defined as follows: σ(k) <= 0 ∀t <= tc; equality only holds for t = tc and k = kc). Inclusion of the interface upward movement leads to earlier destabilization of the system. Increasing viscosity for increasing CO2 concentration stabilizes the system. The theoretical results are compared to bulk flow visual experiments using the Schlieren technique to follow finger development in aquifer sequestration of CO2. In the appendix, we include a detailed derivation of the dispersion relation σ(k) in the Hele-Shaw case [C. T. Tan and G. M. Homsy, Phys. Fluids 29, 3549-3556 (1986)] which is nowhere explicitly given. [ABSTRACT FROM AUTHOR]

Abstract: Sorption isotherms of CO2, CH4 and N2 are determined at 318K and 338K for pressures up to 16MPa in dry Selar Cornish coal using the manometric method. Both equilibrium sorption and desorption were measured. The desorption isotherms show that there is no hysteresis in N2, CH4 sorption/desorption on coal. The time to achieve equilibrium depends on the gases and is increasing in the following order: He, N2, CH4, and CO2. The results show that the sorption ratio between the maximum in the excess sorption N2:CH4:CO2 =1:1.5:2.6 at 318K and 1:1.5:2.0 at 338K. Obtained ratios are within the range quoted in the literature. Swelling and shrinkage induced by CO2 injection and extraction from Selar Cornish coal have been measured. The experiments have been conducted on unconfined cubic samples using strain gauges measurements at 321K for pressures up to 4.1MPa. It has been found that the mechanical deformation is fully reversible. The density of CO2 in its sorbed phase, has been extrapolated from the excess sorption isotherm calculated including the swelling. The resulting value is unrealistically high. Possible reasons for this behavior are discussed in the text. Absolute sorption for CO2 has been estimated considering also the change in the coal volume due to swelling. The resulting isotherm calculated with or without the swelling is almost the same. [ABSTRACT FROM AUTHOR]

Abstract: In this paper we investigate the mass transfer of CO2 injected into a homogenous (sub)-surface porous formation saturated with a liquid. In almost all cases of practical interest CO2 is present on top of the liquid. Therefore, we perform our analysis to a porous medium that is impermeable from sides and that is exposed to CO2 at the top. For this configuration density-driven natural convection enhances the mass transfer rate of CO2 into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO2 into the liquid. The effects of aspect ratio and the Rayleigh number, which is dependent on the characteristics of the porous medium and fluid properties, are studied. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number. The results of this paper have implications in enhanced oil recovery and CO2 sequestration in aquifers. [Copyright &y& Elsevier]

This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO 2) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO 2) and an aqueous phase that contains both carbon dioxide (CO 2) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl 2) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25°C) and at the reservoir-conditions (80°C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Hückel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO 2) on the stability of low-salinity foam-laminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO 2) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO 2) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO 2) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl 2 i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25°C) and at (80°C) than the high-salinity case for both (25°C) and (80°C). Moreover, high carbon dioxide (CO 2) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of "Smart Water Assisted Foam (SWAF) Flooding". It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive. • Surface complexes play an important role for creating a stable foam and water film(s) between oil & rock. • Using surface complexation modelling we can determine the charge on the calcite-water-oil surface(s). • A low salinity leads to less screening of the surface potential, and thus improves the stability of the foam film. • A high CO 2 concentration leads to a decrease of the surface charge, and thus destabilizes the foam film. • SWAF-process under the optimum conditions make the proposed new hybrid EOR-process economically & environmentally attractive. [ABSTRACT FROM AUTHOR]

In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir's formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value ( 6.17 ), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 6 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 ∘ C) and 170 (s − 1 ) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 ( ∘ C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is ( 7.99 % ), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid. [ABSTRACT FROM AUTHOR]