Summary Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering oil/water interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material-balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wettability indices, determined by the U.S. Bureau of Mines (USBM) centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A reasonable agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption. Introduction The Yates field, discovered in 1926, is a massive naturally fractured carbonate reservoir located at the southern tip of the Central Basin Platform in the Permian Basin of west Texas. The main production comes from a 400-ft-thick San Andres formation with average matrix porosity and permeability of 15% and 100 md, respectively, and a fracture permeability of greater than 1,000 md. The primary oil recovery mechanism at the Yates field is a gravity-dominated double displacement process in which the gas cap is inflated through nitrogen injection. Dilute surfactant pilot tests have been conducted at the Yates field since early 1990. The surfactant, Shell 91-8 nonionic ethoxy alcohol, was diluted with produced water to a concentration (3,100-3,880 ppm) much higher than the critical micelle concentration (CMC) and was injected into the oil/water transition zone below the oil/water contact (OWC) for both single-and multiwell tests. Single- and multiwell pilot tests demonstrated improved oil recovery (IOR) and a reduced water/oil ratio in response to dilute surfactant treatments. Previous viscous flooding experiments with Yates reservoir cores indicated that the injection of dilute surfactants resulted in improved oil recovery when compared to the injection of brine.1 However, in a fractured reservoir such as Yates, the success of surfactant flooding depends on how effectively the surfactant residing in the fracture spaces can penetrate the matrix. Thus, static sponta neous imbibition was believed to better represent the fluid exchange between the rock matrix and fracture network. Spontaneous imbibition can be driven by either capillary or gravity forces and is a function of interfacial tension, wettability, density difference, and characteristic pore radius. Austad et al. investigated spontaneous surfactant imbibition into oil-saturated and low-permeability (less than 10 md) chalk cores.2–4 They concluded that, for water- and mixed-wet cores using an anionic surfactant, the early-time recovery mechanism was countercurrent movement, followed by gravity displacement at late time. For oil-wet cores using a cationic surfactant, the primary displacement mechanism was countercurrent movement. Countercurrent movement was believed to be a function not only of capillary forces, but also of the Marangoni effect that describes spontaneous interfacial flows induced by an IFT gradient.3,5,6 It was believed that the Marangoni effect created a hydrodynamic shear stress at the oil/water interface that provided additional force to mobilize the displaced oil phase in the direction opposite to the imbibed aqueous phase. For the oil-wet cores, Austad et al. hypothesized that the cationic surfactant improved oil recovery by altering rock wettability.4 In particular, the increased water wettability resulted in a decreased contact angle and increased capillary forces, thus maximizing countercurrent movement. The Yates reservoir is similarly believed to be oil- to mixed-wet. Cationic surfactants, although effective in altering wettability for oil-wet rocks, are too expensive to be implemented in a field treatment. Nonionic and anionic ethoxylated surfactants were selected for the Yates field pilot tests and laboratory studies because they were less expensive than cationic surfactants and they improved oil recovery without forming emulsions. The IOR mechanism for the ethoxylated surfactants used at Yates is different from the mechanism for the cationic surfactants used by Austad et al. The different IOR mechanism at Yates is largely owing to the nature of the highly fractured reservoir with a high-permeability matrix (average 100 md). Gravity is the dominant force in oil recovery for a fractured reservoir (mixed dolomite/sandstone formation).7 For such a gravity-dominated process, oil is displaced from the matrix blocks by cocurrent movement vertically through the top surface. The ethoxylated surfactants used at Yates are believed to quickly distribute monomers along the oil/water interface. These monomers lower the IFT and, while the surfactant is present in the aqueous phase, they may alter the wettability from oil-wet to less oil-wet. Thus, although the wettability alteration may occur, enhancing gravity forces owing to IFT-lowering may be the primary IOR mechanism for the Yates field. The objective of this work is to quantify the relative significance of radial countercurrent movement caused by capillary forces and vertical cocurrent movement caused by gravity during surfactant static imbibition into Yates cores. The importance of IOR mechanisms such as adsorption-dependent wettability alteration, interfacial tension reduction, and surfactant diffusion are illustrated through a comparison of laboratory data and numerical simulation results.

Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering water-oil interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wett ability indices, determined by the U.S. Bureau of Mines centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A good agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption. Single and multi-well pilot tests at Yates also demonstrated oil recovery improvement and water-oil-ratio reduction in response to dilute surfactant treatment. Introduction The Yates field, discovered in 1926, is a massive naturally fractured carbonate reservoir located at the southern tip of the Central Basin Platform in the Permian Basin of West Texas. The main production comes from a 400-foot-thick of San Andres formation, which has average matrix porosity and permeability of 15% and 100 md, respectively, and a fracture permeability of greater than 1,000 md. The primary oil recovery mechanism at the Yates field is a gravity-dominated double displacement process in which the gas cap is inflated via nitrogen injection. Previous viscous flooding experiments using Yates reservoir cores indicated that the injection of dilute surfactants resulted in improved oil recovery (IOR) when compared to injection of brine.1 However, in a fractured reservoir such as Yates, the success of surfactant flooding depends on how effectively the surfactant that resides in the fracture spaces can penetrate the matrix. Thus, static spontaneous imbibition was believed to better represent the fluid exchange between the rock matrix and fracture network. Spontaneous imbibition can be driven either by capillary or gravity forces and is a function of interfacial tension, wett ability, density difference, and characteristic pore radius.

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SPE Members Abstract Laboratory experiments on gas condensate flow behavior were conducted under reservoir conditions. Two North Sea gas condensate reservoirs that have distinct rock and fluid properties were studied. The objectives of the corefloods were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities during in-situ condensation, hydrocarbon recovery and trapping by water injection, and incremental hydrocarbon recovery by subsequent blowdown. It was found that both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate drop out can be somewhat restored by increasing production rate. Phase behavior and interfacial tension influence the extents of gas relative permeability reduction and condensate mobility. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Approximately 27 %PV gas was trapped by water injection. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss. Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system. If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates. Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements. Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates. Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties. Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ drop out versus external injection or in-flowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability. P. 699

Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss.1,2 Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system.3,4 If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates.5 Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements.6 Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates.7,8 Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties.3,9–20 Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ dropout versus external injection or inflowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability.7,21,22 Reported blowdown experiments imply gas recovery depends upon the degree of gas expansion.7,8 The kr results obtained in this study represent gas condensate flow between the far-field and the near-wellbore region. The results are useful input for numerical simulation, especially to test rate- or IFT-sensitive relative permeability functions. Results on hydrocarbon recovery and trapping from water injection and blowdown are beneficial in evaluating improved recovery options for gas condensates. Experimental Procedures Coreflooding experiments were performed under reservoir conditions using rock and fluid samples from two distinct North Sea gas condensate reservoirs. A detailed description of the experimental methods is provided in the Appendix. Briefly, the experiments were conducted in a horizontal coreflood apparatus equipped with in-line PVT and viscosity measuring devices. The entire system experienced in-situ condensate drop out by constant volume depletion (CVD) from above Pd to either the pressure corresponding to CCS, or to the pressure of maximum condensate saturation Scmax Steady-state krg was measured by injecting equilibrated gas (before CCS). Steady-state krg and krc were measured by injecting gas condensate repressurized to above Pd (after CCS). The gas/oil fractional flow rate was defined by the pressure level in the core which was controlled by the core outlet back-pressure regulator. During krg measurements, the injection rate was varied to access rate effects. After the krg or krg and krc measurements to Scmax were completed, water injection was performed to quantify hydrocarbon trapping and recovery. Blowdown followed to evaluate additional hydrocarbon recovery. Recombined Reservoir Fluid Properties. Two North Sea gas condensate reservoir fluids were recombined using separator oil and synthetic gas. Tables 1 and 2 list compositions and PVT properties for the reconstituted fluids. The Pd was 7,070 psig at 250°F for Reservoir A, and 6,074 psig at 259°F for Reservoir B (Table 2). The maximum liquid dropout under constant composition expansion (CCE) was 31.7% for Reservoir A, and 42.5% for Reservoir B (Fig. 1). Reservoir B is a richer gas condensate and exhibits more near-critical phase behavior than Reservoir A.