Executive Summary

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This issue presents 30 papers in six categories, including a spotlight article, as follows.

Spotlight on Data: Dimensionality Reduction. Awotunde evaluates the effectiveness of six dimension-reduction approaches. The paper considers a number of approaches that differ in their mode of operation, but all reduce the number of parameters required in well-control optimization problems. Results show that among the different approaches, the piecewise approach performs better on many problems, but yields widely fluctuating well controls over the field-development time frame. In contrast, the trigonometric approach performs well overall, yielding controls that vary smoothly over time.

Heavy-Oil Characterization and Production. Ratnakar and Dindoruk discuss the importance of diffusion mixing as a dominant process in the absence of convective mixing in various reservoir processes [e.g., carbon dioxide (CO2) flooding of fractured reservoirs, among a plethora of many important ones). In these processes, diffusivity governs the rate and extent of mixing of light hydrocarbons/nonhydrocarbons with the oil that enhances the oil recovery through in-situ viscosity reduction. The authors extend their 2015 experimental work using the pulse-decay concept. In this work, they present a robust inversion technique and resolution of issues with nonlinear regression analysis.

Anand et al. investigate the effects of solvent-injection rate, temperature, and solvent type (n-butane and dichloromethane) on the recovery profile performed on a single-fracture core model. This work combines the knowledge obtained from experimental investigation and analytical modeling using the Butler correlation (Das and Butler 1999) with validated fluid-property models to understand the relative importance of various recovery mechanisms behind vapor/oil gravity drainage—namely, molecular diffusion, asphaltene precipitation and deposition, capillarity, and viscosity reduction.

Fan et al. propose a pressure-gradient-based sand-failure criterion for quantifying sand production and characterizing wormhole propagation as it relates to the cold heavy-oil production with sand (CHOPS) process. The sand-failure criterion isinitially developed at the pore-scale level, while a pseudointeraction force between two neighboring sand grains is proposed to implicitly represent the potential contributions of cementation and geomechanical stresses to the fluidization of sand. The criterion is then extended to a grid scale within a wormhole because the pressure gradient is constant at either a pore scale or a grid scale. With the bottomhole pressure being an input constraint, the proposed sand-failure criterion is validated with good agreement by reproducing production profiles and wormhole propagation from laboratory experiments and a CHOPS well in the Cold Lake Oil Sands Area.

Irani and Ghannadi use time of flight (ToF) to effectively convert spatial variations of temperature into time response of temperature variation at the well sandface in steam-assisted-gravity-drainage (SAGD) processes. ToF defines the time an oil droplet needs to travel through a medium—more specifically, from its current location to the well sandface. By solving the heat transfer and Darcy’s law simultaneously, the ToF is converted into a relationship of temperature vs. time profile at the producer. This approach is applied to SAGD well pairs with different geology, and the temperature-falloff trends are presented.

In a connected SAGD paper, Irani explores the evolution of disturbance (spatial-growth rate) by solving the initial value problem governing the linear stability of the pressure and water-phase velocity normal to the edge of the steam chamber found in the SAGD process. A new model that couples the pressure diffusion equations and condensate leakoff into a reservoir beyond the chamber is formulated. Results suggest that the steam interface in the SAGD process is unstable if it moves faster than the critical velocity. In the ramp-up phase, the velocity at the chamber interface increases until it reaches the instability velocity. Once reached, the instability causes extensive mixing and convection, which reduces the temperature at the interface, causing the interface velocity to reduce to the instability velocity. As a result, the interface grows at the equilibrium velocity of minimum instability velocity (or critical velocity). The vertical/horizontal permeability ratio of the reservoir is a controlling parameter of instability. The calculated oil-production rate at ramp up increases linearly with time, which contradicts Butler’s ramp-up formula that states that rate is correlated to the cubic root of time. Another key finding is that the suggested ramp-up-rate formula is highly dependent upon the reservoir-water mobility, which is supported by field operations in reservoirs with high water mobility such as Suncor/Firebag and Nexen/Long Lake, where the ramp-up time is significantly less than that in reservoirs with low water mobility, such as those in the MacKay River Field.

Enhanced-Oil-Recovery Technologies Assessment. AlSofi et al. further assess surfactant-polymer flooding from previous studies with future plans to pilot the process in mind. They evaluate side effects of these EOR chemicals on upstream facilities and determine mitigation plans if needed. They investigate the surfactant/polymer compatibility with the additives used in processing facilities for demulsification and scale and corrosion inhibition as well as the possible effect of surfactant/polymer on oil/water separation, metal corrosion, and scale inhibition. To this end, they perform a sensitivity-based simulation study to estimate the volumes of produced EOR chemicals. Second, a compatibility study is conducted to evaluate EOR chemical compatibility with oilfield additives. Third, bottles of phase behavior tests were conducted in various aqueous solution compositions to evaluate the effect of EOR chemicals on oil/water separation. On the basis of their results, they conclud that the selected surfactant/polymer implementation would have a manageable effect on separation facilities.

Tang et al. explore the effect of oil on the two flow regimes for one widely used foam model in a simulator. Based on their results, they show that the wet-foam model shifts behavior in the low-quality regimes with no direct effect on the high-quality regime. The dry-out model shifts behavior in the high-quality regimes but not the low-quality regime. At fixed superficial velocities, both models predict multiple steady states at some injection conditions. The authors perform a stability analysis of these states using a simple 1D simulator with and without incorporating capillary diffusion. The steady state attained after injection depends on the initial state. In some cases, it appears that the steady state at the intermediate pressure gradient is inherently unstable, as represented in the model. In some cases, the introduction of capillary diffusion is required to attain a uniform steady state in the medium. The existence of multiple steady states, with the intermediate one being unstable, is reminiscent of catastrophe theory and of studies of foam generation without oil.

Fatemi et al. propose a numerical case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water/oil reservoir. The polymer was designed to have a viscosity of 20 cp in situ. The authors start with 100 realizations of the 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. They allow for the possibility of polymer process failure in situ and viscosity at only 30% of that intended. They test whether the signals of this difference at injection and production wells would be statistically significant in the midst of geological uncertainty. Specifically, they compare the deviation caused by loss of polymer viscosity with the scatter caused by the geological uncertainty using a 95% confidence interval. Among the signals considered, polymer-breakthrough time, minimum oil cut, and rate of rise in injection pressure with polymer injection provide the most-reliable indications of whether a polymer viscosity was maintained in situ.

Tagavifar et al. investigate spontaneous displacement of oil from oil-wet porous media by microemulsion-forming surfactants through simulations and compare the results with existing experimental data for low-permeability cores with different aspect ratios and permeabilities. Microemulsion viscosity and oil contact angles, with and without surfactant, are measured to better initialize and constrain the simulation model. Results show that with such processes, the imbibition rate and the oil recovery scale differently with core dimensions. Specifically, the rate of imbibition is faster in cores with larger diameter and height, but the recovery factor is smaller when the core aspect ratio deviates considerably from unity. With regard to the mechanism of water uptake, their results suggest that microemulsion formation is fast and favored over the wettability alteration in short times; a complete wettability transition from an oil-wet to a mixed microemulsion-wet and surfactant-wet state always occurs at ultralow IFT; wettability alteration causes a more uniform imbibition profile along the core but creates a more diffused imbibition front; and total emulsification is a strong assumption and fails to describe the dynamics and the scaling of imbibition. Wettability alteration affects the imbibition dynamics locally by changing the composition path, and at a distance by changing the flow behavior. Simulations predict that even though water is not initially present, it forms inside the core.

Al-Ibadi et al. examine a numerical simulation of low-salinity waterflooding at the reservoir scale. Various representations of the effective salinity range and weighting function are examined. The dispersion of salinity is compared with a theoretical form of numerical dispersion on the basis of input parameters. Salinity movement is also compared with the analytical solution of the conventional dispersion/advection equation. The authors observed that in advection-dominated flow, the salinity profile moves at the speed of the injected water. However, as dispersion increases, the mixing zone falls under the influence of the faster-moving formation water and, thus, speeds up. To predict the salinity profile theoretically, they modified the advection term of the analytical solution as a function of the formation- and injected-water velocities, Péclet number, and effective salinity range. This important result enables prediction of the salinity transport by this newly derived modification of the analytical solution for 1D flow.

Gong et al. conduct a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a surfactant-alternating-gas (SAG) process in the field after gas injection. In comparison with their previous results, there was no consistent approach to modeling liquid injectivity in a SAG process. In this paper, they propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of their experimental findings. The model represents the propagation of various banks during gas and liquid injection. They first compare the model predictions for linear flow with the coreflood results and obtain good agreement. They subsequently propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The work flow described in this study can be applied to future field applications.

Fredriksen et al. carry out an integrated enhanced-oil-recovery approach in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension, alter wettability, and establish conditions for capillary continuity to improve tertiary CO2-foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. A cationic surfactant is the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place, verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

Fundamentals of Porous Media Flow. Chung et al. propose a rapid and robust method to solve the elliptic flow equation at the microscale. Segmented micro-computed-tomography (micro-CT) images were used for the calculation of local conductivity in each voxel. The elliptic flow equation is then solved on the images using the finite-volume method. The numerical method is optimized in terms of memory usage using sparse matrix modules to eliminate memory overhead associated with both the inherent sparsity of the finite-volume two-point flux-approximation method, and the presence of zero conductivity for impermeable grain cells. The estimated permeabilities for a number of sandstone and carbonate micro-CT images are compared against estimation of other solvers, and results show a difference of approximately 11%. However, the computational time is 80% lower. Local conductivity can furthermore be assigned directly into matrix voxels without a loss in generality, hence allowing the pore-scale finite-volume solver to be able to solve for flow in a permeable matrix as well as open pore space.

Khan et al. conduct a formation-damage experimental study on synthetic homogeneous and vuggy cores. Glass beads of 1.0 mm are sintered to form a uniform core with a porosity of 42%, and finer-sized glass beads (25 and 100 µm) are used as the infiltrates. Glass beads are used as the matrix and infiltrate to reduce surface forces, and the flow is gravity dominated. Dissolvable inclusions are added during the sintering process to create vugs in the core. The pore-size to vug-size ratio is 1:100. The injected-particle sizes are chosen such that straining is the dominant trapping mechanism during the flow experiment. Infiltrate particles are injected at different flow configurations, and the resultant porosity, permeability, and effluent volume are measured. The results can be summarized as follows: Vugs get up to 32% smaller because of the flow for the infiltrate, while the maximum change in the porosity is observed at the bottom end of the core; vug shape changes to a smoother and rounded surface; and particles go deeper (8 mm more) into the formation when vugs are present, causing damage deeper inside the formation.

Meng et al. study oil recovery by countercurrent spontaneous imbibition from 2D matrix blocks with different boundary conditions using numerical calculations. The numerical results show that the shape of imbibition-recovery curves changes with different boundary conditions. Therefore, the imbibition curves did not correlate well with a constant parameter. A modified characteristic length was proposed by a combination of Ma et al. (1997) and theoretical characteristic length. The modified characteristic length is a function of imbibition time, and the shape of imbibition curves could be changed using the modified characteristic length. The overall imbibition curves were closely correlated using the modified characteristic length. Finally, the modified characteristic length was verified by experimental data for imbibition with different boundary conditions.

Føyen et al. use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior. In this work, the development of displacement fronts are visualized during the onset period, using two-dimensional paperboard models and core plugs imaged using positron emission tomography. The new experimental results provide insight into the dynamics during the initial spontaneous imbibition period. Controlled two-dimensional paperboard experiments demonstrate that restricted wetting phase flow through the surface exposed to water causes irregular saturation fronts and deviation from the square-root-of-time behavior during the onset period. Local restriction of the wetting phase flow is observed during spontaneous imbibition in sandstone core plugs as a result of nonuniform wetting preference. The presence of nonuniform wetting results in unpredictable spontaneous imbibition behavior, with induction time (delayed imbibition start) and highly irregular fronts. Without imaging, the development of irregular saturation fronts cannot be observed locally; hence, the effect cannot be accounted for, and the development of spontaneous imbibition in the core erroneously interpreted as a corescale wettability effect. This underlines the undeniable need for a homogenous wettability preference through the porous medium when performing laboratory spontaneous imbibition measurements. Their observations of nonuniform wetting preference will affect Darcy-scale wettability measurements, scaling, and modeling.

Andersen et al. develop a modeling approach to simulate and interpret spontaneous imbibition of water from Cr(III)-acetatehydrolyzed-polyacrylamide gel into adjacent oil-saturated rock matrix. Simulations are compared to experiments on the core scale, using two different boundary conditions: all faces open and two-ends-open free spontaneous imbibition. Capillary forces enable water (used as gel solvent) to enter the rock matrix. They develop a theory that describes the gel as a compressible porous medium and describes the flow of water through gel. The polymer structure of the gel is proposed to constitute a gel matrix of constant solid volume. Gel porosity, defined by the volume fraction of solvent, is modeled as a function of pore pressure and gel compressibility. Gel permeability is modeled as function of gel porosity using a Kozeny-Carman approach. The flow equations are solved simultaneously by implementing the proposed description into a core-scale simulator. The simulated flow of water through and from the gel occurrs in a transient manner, driven by the coupled gradients in gel fluid pressure and gel porosity. Gel porosity initially decreases in a layer close to the core surface because of reduced aqueous pressure, and continues to decrease in layers away from the core surface. The propagation rate is controlled by two main gel parameters: First, gel compressibility controls the pressure gradient within the gel network, and the amount of water transported from the outer part of the gel toward the core surface to balance the pore pressure; and, second, gel permeability limits how fast water can flow within the gel at a given pressure gradient, thus increasing the time scale of the overall imbibition process.

Hassan et al. present a robust pore-imaging approach that uses confocal laser scanning microscopy (CLSM) to obtain high-resolution 3D images of etched epoxy pore casts of the highly heterogeneous carbonates. In their approach, they increase the depth of investigation for carbonates 20-fold, from 10 µm reported by Fredrich (1999) and Shah et al. (2013) to 200 µm. In addition, high-resolution 2D images from scanning electron microscopy have been correlated with the 3D models from CLSM to develop a multiscale imaging approach that covers a range of scales, from millimeters in three dimensions to micrometers in two dimensions. The developed approach is implemented to identify various pore types in limestone and dolomite samples.

Zuo and Armstrong study the impact of wettability alteration on relative permeability by integrating laboratory steady-state experiments with in-situ high-resolution imaging. Wettability alteration at the core scale is characterized by conventional laboratory methods and history matching is used for relative permeability determination to account for capillary-end effect. It is found that because of wettability alteration from water-wet to mixed-wet conditions, oil relative permeability decreases while water relative permeability increases slightly. For the mixed-wet condition, the pore-scale data demonstrate that the interaction of viscous and capillary forces results in viscous-dominated flow, whereby nonwetting phase is able to flow through the smaller regions of the pore space. Overall, this study demonstrates how special-core-analysis techniques can be coupled with pore-scale imaging to provide further insights on pore-scale flow regimes during dynamic coreflooding experiments.

Fracture Stimulation. Xue et al. build upon their previous approach to propose a novel diagnostic tool for the interpretation of the characteristics of complex fracture systems and drainage volume. They used the w(τ) and instantaneous recovery ratio (IRR) plots for the identification of characteristic signatures that imply complex fracture geometry, formation linear flow, partial reservoir completions, and fracture-interference/compaction effects during production. The w(τ) analysis gives one the fracture surface area and formation diffusivity, while the IRR analysis provides additional information on fracture conductivity. In addition, quantitative analysis is conducted using the novel w(τ) plot to interpret fracture-interference time, formation permeability, total fracture surface area, and stimulated reservoir volume. The major advantages of this current approach are the model-free analysis without assuming planar fractures, homogeneous formation properties, and specific flow regimes. In addition, the w(τ) plot captures high-resolution flow patterns not observed in traditional pressure-transient/rate-transient analysis, leading to a simple and intuitive understanding of the transient-drainage volume and fracture conductivity.

Wang et al. establish a pseudosteady-state (PSS) productivity model of a fractured horizontal well, which has the flexibility of accounting for the complexity of fracture-network dimensions. A semianalytical solution is then presented in the generalized matrix format through coupling reservoir- and fracture-flowing systems. Subsequently, several published studies on the PSS productivity calculation of a single fracture are used to verify this model, and a 3D transient numerical simulation of an orthogonal fracture network is used to perform further verification. The authors show that their results agree very well with benchmarked results. On the basis of the model, they provide a detailed analysis on the productivity enhancement of the fracture-network/optimization workflow using unified fracture design.

Zhu et al. develop a predictive model for fracture width and conductivity when unpropped, highly conductive channels are generated during stimulation. This model considers the combined effects of pillar and fracture-surface deformation, as well as proppant embedment. The influence of the geomechanical parameters relates to the formation and the operational parameters of the stimulation are analyzed using the proposed model. A number of important findings regarding compaction in reaction to stress along with others are shown in this paper.

Zolfaghari et al. investigate shale/water interactions by measuring the mass of total ion produced (TIP) during water-imbibition experiments. They conduct two sets of imbibition experiments at low-temperature/low-pressure (LT/LP) and high-temperature/high-pressure (HT/HP) conditions. They also study the effects of rock surface area, temperature, and pressure on TIP during imbibition experiments. Laboratory results indicate that pressure does not have a significant effect on TIP, whereas increasing the rock surface area and temperature both increase TIP. They use flowback-chemical data and laboratory data of ion concentration to estimate the fracture surface area for two wells completed in the Horn River Basin, Canada. For both wells, the estimated fracture surface area values from LT/LP and HT/HP test results have similar orders of magnitude (approximately 5.0×106 m2) compared with those calculated from production and flowback rate-transient analysis (approximately 106 m2).

Jiang et al. establish a semianalytical solution to quantify the combined effects of non-Darcy flow and stress sensitivity on the transient pressure behavior for a fractured horizontal well in a naturally fractured reservoir. More specifically, the Barree-Conway model was used to quantify the non-Darcy flow behavior in the hydraulic fractures (HFs), while the permeability modulus is incorporated into mathematical models to take into account the stress-sensitivity effect. In this way, the resulting nonlinearity of the mathematical models is weakened by using Pedrosa’s transform formulation. Then, a semianalytical method is applied to solve the coupled nonlinear mathematical models by discretizing each HF into small segments. Furthermore, the pressure response and its corresponding derivative type curve are generated to examine the combined effects of non-Darcy flow and stress sensitivity. In particular, stress sensitivity in HF and natural-fracture (NF) subsystems can be respectively analyzed, while the assumption of an equal stress-sensitivity coefficient in the two subsystems is no longer required. It was found that non-Darcy flow mainly affects the early stage bilinear and linear flow regime, leading to an increase in pressure drop and pressure derivative. The stress-sensitivity effect is found to play a significant role in those flow regimes beyond the compound-linear flow regime. The existence of non-Darcy flow makes the effect of stress sensitivity more remarkable, especially for the low-conductivity cases, while the stress sensitivity in fractures has a negligible influence on the early time period, which is dominated by non-Darcy flow behavior. Other parameters such as storage ratio and crossflow coefficient are also analyzed and discussed. It is found from field applications that the coupled model tends to obtain the most-reasonable matching results, and for that model there is an excellent agreement between the measured and simulated pressure response.

Jiang et al. theoretical models are formulated, validated, and applied to evaluate the transient pressure behavior of a horizontal well with multiple fractures in a tight formation by taking stress-sensitive fracture conductivity into account. A new slab-source function in the Laplace domain is developed to describe the transient pressure responses caused by fluid flow from the matrix to the fracture, and a new solution is derived to describe the fluid flow in the fracture under the stress-sensitivity effect. Subsequently, a semianalytical method is applied by discretizing each hydraulic fracture into small segments, and a linearization scheme and an iteration method are adopted to deal with the nonlinear problem in the Laplace domain. Meanwhile, a modified superposition principle is proposed and applied to generate the pressure distributions for buildup tests with consideration of stress-sensitive fracture conductivity. For pressure-drawdown tests, it is found that gradual increases in both pressure drop and pressure derivative occur over time because of the partial closure of the fractures. The stress-sensitivity effect in fractures becomes more evident with a smaller fracture conductivity and a larger fracture-permeability modulus. From the pressure-buildup curves, a one-fourth-slope line characteristic of the bilinear-flow period and constant derivatives of 0.5 representing a pseudoradial-flow regime can be clearly observed. Only fracture conductivity near the wellbore at the shut-in time can be estimated from the buildup pressures obtained in this work, whereas pressure-buildup analysis derived from the traditional superposition principle will result in an erroneous evaluation of the stress-sensitive fracture conductivity. It is also found that the effect of permeability hysteresis in the fractures has a negligible impact on the pressure-buildup responses.

Guk et al. develop a rigorous and unified dimensionless optimization technique with type curves for the case of multiple transverse fractures in a horizontal well—an extension of unified fracture design. Multiple fractures include the proppant number, penetration ratio, dimensionless conductivity, and aspect ratio for each fracture. The direct boundary element method is used to generate the dimensionless productivity index for a given range of these parameters (28,000 runs) for the pseudosteady-state case. Finally, total well dimensionless productivity index is plotted as a function of the number of fractures for various proppant numbers. The effect of minimum fracture width is studied, and the optimization curves are adjusted for three cases of minimum fracture width. The dimensionless type curves can be used to identify the optimal number of fractures and their geometry for a given set of parameters, without running a more complicated numerical model multiple times. First, the proppant mass (and hence, proppant number) used for the fracture design can be selected on the basis of economic or other considerations. For this purpose, a relationship between total dimensionless productivity index and proppant number, which accounts for the minimum fracture width requirement, is provided. Then, the optimal number of fractures can be calculated for a given proppant number using the generated type curves with minimum width constraints.

Unconventional Reservoirs. Berawala et al. develop a mathematical 1D+1D model that involves a high-permeability fracture extending from a well perforation through symmetrically surrounding shale matrix with low permeability. Gas in the matrix occurs in the form of adsorbed material attached to kerogen (modeled by a Langmuir isotherm) and as free gas in the nanopores. The pressure gradient toward the fracture and well perforation causes the free gas to flow. With pressure depletion, gas desorbs out of the kerogen into the pore space and then flows to the fracture. When the pressure has stabilized, desorption and production stop. The model allows for intuitive interpretation of the complex shale-gas-production system. Furthermore, the current model creates a base that can easily incorporate nonlinear-flow mechanisms and geomechanical effects that are not readily found in standard commercial software, and further be extended to field-scale application.

Baek and Akkutlu propose a new equation of state to predict the density of the redistributed fluid mixtures in nanopores under the initial reservoir conditions. A new volumetric method was presented to ensure the density variability across the measured pore-size distribution to improve the accuracy of predicting hydrocarbons in place. The approach allows one to account for the bulk hydrocarbon fluids and the fluids under confinement. Multicomponent fluids with redistributed compositions are capillary condensed in nanopores at the lower end of the pore-size distribution of the matrix (<10 nm). The nanoconfinement effects are responsible for the condensation. During production and pressure depletion, the remaining hydrocarbons become progressively heavier. Hence, hydrocarbon vaporization and desorption develop at extremely low pressures. Consequently, hydrocarbon recovery from these small pores is characteristically low.

In a second paper, Baek and Akkutlu show the importance of using hydrocarbon mixtures, revealing that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of COinjection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules are the primary drivers that promote the recovery, whereas pressure depletion is not effective on the recovery. The results for N2 injection were also recorded for comparison.

Vladimir Alvarado, SPE J. Executive Editor,

University of Wyoming