This month, we have 25 papers categorized under five topics.
Unconventional Resources. Akinluyi and Hazlett use analytical methods to model oil recovery during lean-gas reinjection in “zipper” fractures in oil shales. Zipper fractures are a scheme in which transverse fractures that cross a horizontal injection well allow near-linear-flow flooding to complementary fractures that cross a parallel horizontal production well.
Sangnimnuan et al. develop a coupled fluid-flow/geomechanics model to predict stress evolution in unconventional reservoirs with a complex fracture geometry. An embedding-discrete-fracture model is used to characterize stress evolution associated with depletion.
Pu et al. simulate how pore-size distribution affects phase and flow behavior in nanopores of the Bakken oil shale during CO2/N2 flue-gas flow.
Teklu et al. measure permeability (to nitrogen) and porosity hysteresis of nano-, micro-, and millidarcy cores under net stresses ranging from 500 to 4,500 psi. Tighter formations are found to be more sensitive to stress.
Liu et al. study the macroscopic mechanical and microscale structural changes in the Chinese Wufeng shale during supercritical CO2 fracturing. Supercritical CO2 is shown to change rock microstructure and make some minerals (e.g., calcite) fracture more easily.
Padin et al. conduct low-salinity osmotic tests in low-clay, organic-rich Eagle Ford carbonate scales. To explain the results, a model is developed that is based on osmosis driving low-salinity brine into high-salinity cores. The work suggests that water imbibition cannot be explained by capillarity alone.
Cai et al. develop a data-analysis tool using nonparametric smoothing models to identify drillsites in tight shale reservoirs with economic potential. The tool finds that four predictor variables can predict “hot zones” for 2,064 Marcellus wells.
Imaging. Zou et al. compute relative permeability from in-situ pore-scale-imaged fluid distributions. Steady-state flow tests are performed on a homogeneous Bentheimer sandstone core. Measured and computed oil relative permeability are in close agreement across the entire saturation range.
Wang et al. use nuclear-magnetic-resonance (NMR) imaging to investigate mechanisms of 5.5-cp oil mobilization in a 0.2-md sandstone core during cyclic exposure to CO2. Although oil was mobilized in all pores, oil in the largest pores is four times more likely to be mobilized than in the smallest pores.
Liang et al. use computed-tomography measurements of water blocks in low-permeability rocks as a means to understand scaling and remedy production impairment. Capillary discontinuity at a fracture face is found to cause the majority of permeability reduction for a water-wet system.
Afrough et al. use magnetic-resonance imaging of a high-pressure CO2 displacement, with a focus on fluid/surface interactions and fluid behavior. During immiscible displacement of decane by CO2, the pore-surface area wetted by decane monotonically decreased at saturations less than 0.25 and demonstrated development of a noncontinuous wetting film on the pore surface.
Enhanced Oil Recovery. AlQuaimi and Rossen propose a new capillary number for fractures that incorporates geometrical characterization of the fracture that is dependent on a force balance on a trapped ganglion. The new definition is validated with laboratory experiments using five distinctive model fractures.
Bidhendi et al. examine oil/water interfacial visocoelasticity as an alternative mechanism for enhanced oil recovery during “smart” waterflooding. During corefloods, oil recovery factor was consistently greater with increased interfacial viscosity for the crude-oil/brine/rock system examined in this study.
Torrealba and Johns develop a microemulsion phase-behavior equation-of-state model using empirical trends in chemical potentials. The model is benchmarked against experimental data considering both pure alkane and crude-oil cases.
Zhang et al. consider the role of the Marangoni effect in producing nanoemulsions that they speculate might improve waterflooding of heavy oils. The paper studies the mechanism of emulsification under low- or no-stress conditions. As in the past, advocating Marangoni effects and emulsification for oil recovery is expected to be controversial.
Irani discusses subcool (thermodynamic steam-trap) control in steam-assisted-gravity-drainage (SAGD) production wells. The study presents a method to calculate the liquid-pool level from the temperature profile in observation wells, and liquid-pool shrinkage versus time.
Temperature and Pressure-Transient Analysis. Mao and Zeidouni present a method to account for fluid-property variations during temperature-transient analysis. The method is shown to improve permeability estimates by 60% for the conditions considered in the paper. The method is extended for use in damaged reservoirs.
Xiao et al. present a semianalytical methodology for pressure-transient analysis of a multiwell-pad-production scheme in shale gas reservoirs. The focus here is on flow regimes and multiwell interference. Well rate is found to determine distortion of pressure curves, whereas fracture length, well spacing, and fracture spacing determine when multiwell pressure interference occurs.
Hazlett and Babu model transient-inflow performance from analytical line-source solutions for arbitrary-trajectory wells. They present two semianalytic, single-phase, constant-rate solutions to the diffusivity equation for an arbitrarily oriented uniform-flux line source in a 3D, anisotropic, bounded system in Cartesian coordinates.
Machado et al. provide analytical solutions for wellbore pressure during an injection/falloff test under radial conditions in homogeneous porous media where the injected fluid was carbonated water.
Stimulation and Flow Assurance. Majid et al. use a high-pressure flow loop to investigate gas-hydrate formation and particle transportability in fully and partially dispersed multiphase flow systems. The average hydrate-growth rate and hydrate agglomeration was found to be more severe as the mixture velocity decreased from 3 to 0.9 m/s. A mechanism for hydrate growth at various multiphase-flow conditions is presented.
Sugiyama et al. investigate asphaltene association with the goal of predicting asphaltene precipitation. A “digital oil” is constructed to model a light crude oil based on the gas, light and heavy fractions, and asphaltenes in a light crude oil. Calculated densities and viscosity changes are consistent with experimental observations.
Kumar et al. explore the effect of oil saturation on the optimal acid-injection rate during acidizing of carbonate outcrop cores at 200°F. Compared with brine- or oil-saturated cores, cores at residual oil saturation experience acid breakthrough with less injected volume.
Zhang et al. use statistical analysis to study static settling of water-in-oil emulsions. A water-cut model, a viscosity-prediction model, and a model for displacement of water droplets are combined to describe a settling simulation.
Yuan and Moghanloo develop analytical solutions to model nanofluid precoating as a method to reduce fines migration in radial systems saturated with two mobile immiscible fluids.
Randy Seright, SPE J. Executive Editor,
New Mexico Institute of Mining and Technology