Foam is utilized in enhanced oil recovery and CO₂ sequestration. Surfactant-alternating-gas (SAG) is a preferred approach for placing foam into reservoirs, due to it enhances gas injection and minimizes corrosion in facilities. Our previous studies with similar permeability cores show that during SAG injection, several banks occupy the area near the well where fluid exhibits distinct behaviour. However, underground reservoirs are heterogeneous, often layered. It is crucial to understand the effect of permeability on fluid behaviour and injectivity in a SAG process. In this work, coreflood experiments are conducted in cores with permeabilities ranging from 16 to 2300 mD. We observe the same sequence of banks in cores with different permeabilities. However, the speed at which banks propagate and their overall mobility can vary depending on permeability. At higher permeabilities, the gas-dissolution bank and the forced-imbibition bank progress more rapidly during liquid injection. The total mobilities of both banks decrease with permeability. By utilizing a bank-propagation model, we scale up our experimental findings and compare them to results obtained using the Peaceman equation. Our findings reveal that the liquid injectivity in a SAG foam process is misestimated by conventional simulators based on the Peaceman equation. The lower the formation permeability, the greater the error.

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Aqueous foam is a dispersion of gas in liquid, where the liquid acts as the continuous phase and the gas is separated by thin liquid films stabilized by a surfactant. Foam injection is a widely used technique in various applications, including CO2 sequestration, enhanced oil recovery, soil remediation, etc. Surfactant-alternating-gas (SAG) is a preferred approach for foam injection, and injectivity plays a vital role in determining the efficiency of the SAG process. Different gases can be applied depending on the process requirements and availability. However, the underlying mechanisms by which gas composition impacts injectivity are not yet fully understood. In this work, the effect of gas composition on fluid behavior and injectivity in a SAG process was investigated using three gases: N2, CO2, and Kr. Our observations revealed that gas solubility in liquid was key for the formation and evolution of liquid fingers, and therefore was very important for liquid injectivity. A lower gas solubility in liquid led to a slower increase in surfactant solution injectivity. In addition, the development of surfactant solution injectivity took significantly longer when the surfactant solution was partially pre-saturated compared to when it was unsaturated. Additionally, the propagation of the collapsed-foam bank during gas injection was accelerated when the gas had a greater solubility in water.@en

Large volumes of carbon dioxide (CO₂) captured from carbon emission source can be stored in deep saline aquifers as a mean of mitigating climate change. The deep saline aquifers are naturally heterogeneous at multiple scales. It is important to generate representative multiscale heterogeneous fields of various hydrogeologic properties and understand storage safety by studying CO₂ migration and distribution in such fields. In this work, a new multiscale heterogeneous model with partly fine multi-facies heterogeneous domain is proposed. A method based on transition probability theory is referred to establish a multi-facies model. A new multiscale heterogeneous model with partly fine multi-facies heterogeneous domain is built up according to the categorized permeability data obtained from the Geological Carbon Storage Frio site in USA. TOUGH2/ECO2N is applied to simulate CO₂ migration and distribution in such a multiscale heterogeneous model. The CO₂ plume shows obvious viscous fingering and non-uniform migration both in layered and vertical directions, implying vertical and horizontal heterogeneity which cannot be represented by a single-scale model or simulated with the assumption of homogeneous formation. The profile of CO₂ migration shown in the numerical simulation at a time of 10 days is in a good accordance with the seismic data of Frio situ in qualitative and quantitative aspects.

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Surfactant-alternating-gas (SAG) is a preferred method of foam injection, which is a promising means of enhanced oil recovery. Liquid injectivity in a SAG process is commonly problematic. Our previous studies suggest that the liquid injectivity can be better than expected due to the existence of a collapsed-foam region formed during the gas-injection period ahead of the liquid-injection period. A single superficial velocity was used in those studies to examine the flow behavior during gas- and liquid-injection periods, separately. However, in radial flow from an injection well, superficial velocity decreases with distance from the injection well. Understanding the effect of superficial velocity on gas and liquid injectivities is important, but remains unexplored. In this study, we first examine gas injection at different superficial velocities following foam injection. We then study the effect of liquid superficial velocity on the liquid injectivity following a similar volume of gas injection. Our results show that during a prolonged period of gas injection following foam, the propagation velocity and the total mobility of the collapsed-foam bank are not significantly affected by the gas superficial velocity. During liquid injection after a period of gas injection, the dimensionless propagation velocities and the total mobilities of the forced-imbibition bank and the gas-dissolution bank follow a power-law dependence on the liquid superficial velocity. Liquid fingering through the weakened-foam region shows strongly shear-thinning behavior. It is also observed from X-ray computer-tomography experiments that the liquid fingers are wider if the liquid superficial velocity is greater. The impact of the shear-thinning behavior on the estimation of liquid injectivity in a field application is the subject of a companion paper.

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Surfactant-alternating-gas (SAG) is a favored method of foam injection, which has been proved as an efficient way for enhancing oil recovery. However, foam flow is extremely complicated, and there are still unsolved problems for foam application. One is liquid injectivity. Our previous studies suggest that the injectivity in a SAG process is determined by propagation of several banks near the injection well that are not represented by current foam models. Uniform bank properties were assumed. However, in a companion paper, our experimental results show that the dimensionless propagation velocity and the total mobility of banks during the liquid-injection period depends on superficial velocity. Shearing-thinning behavior is observed. In radial flow, the superficial velocity varies with distance from the well. In this study, we scale-up the experimental results using a radial bank-propagation model. The comparison of liquid injectivity estimated from conventional foam simulators (Peaceman equation) and the bank-propagation model show that the conventional foam models cannot represent the effect of the superficial-velocity-dependent fluid properties during liquid injection in a SAG process. The shear-thinning behavior can lead to much better liquid injectivity than expected, which should be accounted for in a field application of a SAG foam process.

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A surfactant alternating gas (SAG) process is often the injection method for foam, on the basis of its improved injectivity over direct foam injection. In a previous study, we reported coreflood experiments on liquid injectivity after foam flooding and liquid injectivity after injection of a gas slug following steady-state foam. Results showed that a period of gas injection is important for the subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored. In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in an SAG process in a field core. Nitrogen and surfactant solution are either coinjected or injected separately into the sandstone core sample. The experiments are conducted at an elevated temperature of 90℃ with a backpressure of 40 bar. Differential pressures are measured to quantify gas and liquid injectivities. Computed tomography (CT) scanning is applied to relate water saturation to mobility. During the injection of a large gas slug following foam, a bank in which foam completely collapses or greatly weakens forms near the inlet and propagates slowly downstream. During the subsequent period of liquid injection, liquid flows through the collapsed-foam bank much more easily than further downstream. Beyond the collapsed-foam region, liquid first imbibes into the whole cross section. In this region, liquid flows mainly through a finger of high liquid saturation. Our CT results suggest a revision of our earlier interpretation; the process of gas dissolution does not merely follow fingering but is evidently directly involved in the fingering process. Our results suggest that, in radial flow, the small region of foam collapse very near the well greatly improves injectivity. The subsequent gas and liquid slugs behave near the wellbore, affecting injectivity, in a way similar to the first slugs. Thus, the behavior and modeling of the first gas slug and first subsequent liquid slug is representative of near-well behavior in an SAG process. The trends observed in our previous work are reproduced in a low-permeability field core.

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Surfactant-alternating-gas (SAG) is often the injection method for foam enhanced oil recovery (EOR) in order to improve injectivity. However, liquid injectivity can be very poor once foam is created in the near-wellbore region. In a previous study, we reported core-flood experiments on liquid injectivity after foam flooding and liquid injectivity after a period of gas injection following foam. Results showed the importance of the gas slug to subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored. In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in a SAG process. We inject nitrogen foam, gas and surfactant solution into a sandstone core sample. The experiments are conducted at a temperature of 90°C with 40-bar back pressure. Pressure differences are measured to quantify the injectivity and supplemented with CT scans to relate water saturation to mobility. We find that during prolonged gas injection in the first gas slug following foam, a collapsed-foam region forms near the inlet due to the interplay of evaporation, capillary pressure and pressure-driven flow. This region slowly propagates downstream. During subsequent liquid injection, liquid mobility is much greater in the collapsed-foam region than downstream, and liquid sweeps the entire core cross section there rather than a single finger. In the region beyond the collapsed-foam region, liquid fingers through foam. Liquid flow converges from the entire cross section to the finger through the region of trapped gas. During injection of the second gas slug, the liquid finger disappears quickly as gas flows in, and strong foam forms from the very beginning. A collapsed-foam region then forms near the inlet and slowly propagates downstream with a propagation velocity and mobility similar to that in the first gas slug. Behavior of the second liquid slug is likewise similar to that of the first liquid slug. Our results suggest that, in radial flow, the small region of foam collapse very near the well is crucial to injectivity because of its high mobility. The subsequent gas and liquid slugs behave like the first slugs. The behavior of the first gas slug and subsequent liquid slug is thus representative of near-well behavior in a SAG process.@en

Surfactant-alternating-gas (SAG) is a favored method of foam injection, in part because of excellent gas injectivity. However, liquid injectivity is usually very poor in SAG. We report a core-flood study of liquid injectivity under conditions like those near an injection well in SAG application in the field, i.e., after a prolonged period of gas injection following foam. We inject foam [gas (nitrogen) and surfactant solution] into a 17-cm-long Berea core at temperature of 90 °C with 40 bar back pressure. Pressure differences are measured and supplemented with CT scans to relate water saturation to mobilities. Liquid injectivity directly following foam is very poor. During prolonged gas injection following foam, a collapsed-foam region forms near the inlet and slowly propagates downstream, in which water saturation is reduced. This decline in liquid saturation reflects in part liquid evaporation, also pressure-driven flow and capillary effects on the core scale. In the collapsed-foam region, liquid mobility during subsequent liquid injection is much greater than downstream, and liquid sweeps the entire core cross section rather than a single finger. Mobility in the region of liquid fingering is insensitive to the quality of foam injected before gas and the duration of the period of gas injection. This implies that at the start of liquid injection in a SAG process in the field, there is a small region very near the well, crucial to injectivity, substantially different from that further out, and not described by current foam models. The results can guide the development of a model for liquid injectivity based on radial propagation of the various banks seen in the experiments.@en

Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity.

In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then 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 conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator’s results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor.

The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.@en

If the aperture distribution is broad enough in a naturally fractured reservoir, even one where the fracture network is highly inter-connected, most fractures can be eliminated without significantly affecting the flow through the fracture network. During a waterflood or enhanced-oil-recovery (EOR) process, the production of oil depends on the supply of injected water or EOR agent. This suggests that the characteristic fracture spacing (or shape factor) for the dual-porosity/dual-permeability simulation of waterflood or EOR in a naturally fractured reservoir should account not for all fractures but only the relatively small number of fractures carrying almost all the injected water or EOR agent (“primary,” as opposed to “secondary,” fractures). In contrast, in primary production even a relatively small fracture represents an effective path for oil to flow to a production well. This distinction suggests that the “shape factor” in dual-permeability reservoir simulations and the repeating unit in homogenization should depend on the process involved: specifically, it should be different for primary and secondary or tertiary recovery. We test this hypothesis in a simple representation of a fractured region with a non-uniform distribution of fracture flow conductivities. We compare oil production, flow patterns in the matrix, and the pattern of oil recovery with and without the “secondary” fractures that carry only a small portion of injected fluid. The role of secondary fractures depends on a dimensionless ratio of characteristic times for matrix and fracture flow (Peclet number), and the ratio of flow carried by the different fractures. In primary production, for a large Peclet number, treating all the fractures equally is a better approximation of the original model, than excluding the secondary fractures; the shape factor should reflect both the primary and the secondary fractures. For a sufficiently small Peclet number, it is more accurate to exclude the secondary fractures in calculation of the shape factor in the dual-porosity/dual-permeability models than to include them and, in effect, assume they play an equally important role in transport to and from the matrix. For waterflood or EOR, in most cases examined, the appropriate shape factor or the repeating-unit size should reflect both the primary and secondary fractures. If the secondary fractures are much narrower than the primary fractures, then it is more accurate to exclude them for calculating the shape factor in a dual-porosity/dual-permeability model. Yet-narrower “tertiary fractures” are not always helpful for oil production, even if they are more permeable than matrix. They can behave as capillary barriers to imbibition, reduce oil recovery. We present a new definition of Peclet number for primary and secondary production in fractured reservoirs that provides a more accurate predictor of the dominant recovery mechanism in fractured reservoirs than the previously published definition.

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Fracture network connectivity and aperture (or conductivity) distribution are two crucial features controlling flow behavior of naturally fractured reservoirs. The effect of connectivity on flow properties is well documented. In this paper, however, we focus here on the influence of fracture aperture distribution. We model a two-dimensional fractured reservoir in which the matrix is impermeable and the fractures are well connected. The fractures obey a power-law length distribution, as observed in natural fracture networks. For the aperture distribution, since the information from subsurface fracture networks is limited, we test a number of cases: log-normal distributions (from narrow to broad), power-law distributions (from narrow to broad), and one case where the aperture is proportional to the fracture length. We find that even a well-connected fracture network can behave like a much sparser network when the aperture distribution is broad enough (α ≤ 2 for power-law aperture distributions and σ ≥ 0.4 for log-normal aperture distributions). Specifically, most fractures can be eliminated leaving the remaining dominant sub-network with 90% of the permeability of the original fracture network. We determine how broad the aperture distribution must be to approach this behavior and the dependence of the dominant sub-network on the parameters of the aperture distribution. We also explore whether one can identify the dominant sub-network without doing flow calculations.

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A large number of oil and gas reservoirs across the world are naturally fractured, f r om which a significant amount of hydrocarbons are produced. Naturally fractured reservoirs, like all reservoirs, are exploited in t w o stages: primary recovery and secondary recovery (sometimes followed by tertiary recovery, i.e. enhanced oil recovery (EOR)), with different recovery mechanisms. During primary production, the reservoir is produced by fluid expansion. In secondary production and EOR, since the fractures are much more permeable than the matrix, the injected water or EOR agent flows rapidly through the fracture network and surrounds the matrix blocks. Oil recovery then depends on efficient delivery of water or EOR agent to the matrix through the fracture network.@en

If the aperture distribution is broad enough in a naturally fractured reservoir, even one where the fracture network is highly inter-connected, most fractures can be eliminated without significantly affecting the flow through the fracture network (Gong and Rossen, 2016). During a waterflood or enhanced-oil-recovery (EOR) process, the production of oil depends on the supply of injected water or EOR agent. This suggests that the characteristic fracture spacing for the dual-porosity/dual-permeability simulation of waterflood or EOR in a naturally fractured reservoir should account not for all fractures but only the relatively small number of fractures carrying almost all the injected water or EOR agent ("primary," as opposed to "secondary," fractures). In contrast, in primary production even a relatively small fracture represents an effective path for oil to flow to a production well. This distinction means that the "shape factor" in dualpermeability reservoir simulators and the repeating unit in homogenization should depend on the process involved: specifically, it should be different for primary and secondary or tertiary recovery. We test this hypothesis in a simple representation of a fractured region with a non-uniform distribution of fracture flow conductivities. We compare oil production, flow patterns in the matrix, and the pattern of oil recovery with and without the "secondary" fractures that carry only a small portion of injected fluid. The role of secondary fractures depends on a dimensionless ratio of characteristic times for matrix and fracture flow (Peclet number), and the ratio of flow carried by the different fractures. In primary production, for a large Peclet number, treating all fractures equally is a better approximation than excluding secondary fractures; the shape factor should reflect both primary and secondary fractures. For a sufficiently small Peclet number, it is more accurate to exclude the secondary fractures. For waterflood or EOR, in most cases examined, the appropriate shape factor or repeating-unit size should reflect both primary and secondary fractures. If secondary fractures are much narrower than primary fractures, then it is more accurate to exclude them. Yet-narrower "tertiary fractures" are not always helpful for oil production, even if they are more permeable than matrix. They can behave as capillary barriers to imbibition, reducing oil recovery. We present a new definition of Peclet number for primary and secondary production in fractured reservoirs that provides a more accurate predictor of dominant recovery mechanism in fractured reservoirs than the previously published definition. @en

The flow properties of naturally fractured reservoirs are dominated by flow through the fractures. In a previous study we showed that even a well-connected fracture network behaves like a much sparser network when the aperture distribution is broad enough: i.e., most fractures can be eliminated while leaving a sub-network with virtually the same permeability as the original fracture network. In this study, we focus on the influence of eliminating unimportant fractures which carry little flow on the inferred characteristic matrix-block size. We model a two-dimensional fractured reservoir in which the fractures are well-connected. The fractures obey a power-law length distribution, as observed in natural fracture networks. For the aperture distribution, because information from the subsurface is limited, we test a number of cases: log-normal distributions (from narrow to broad), and power-law distributions (from narrow to broad). The matrix blocks in fractured reservoirs are of varying sizes and shapes; we adopt the characteristic radius and the characteristic length to represent the characteristic matrix-block size. We show how the characteristic matrix-block sizes increase from the original fracture network to the dominant sub-network. This suggests that the matrix-block size, or shape factor, used in dual-porosity/dual-permeability waterflood or enhanced oil recovery (EOR) simulations or in homogenization should be based not on the entire fracture population but on the sub-network that carries almost all of the injected fluid (water or EOR agent).

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