Executive Summary

This is my last issue as executive editor of SPE Journal. It has been a great experience over the past 3 years, and I really enjoyed working with all the SPE staff, executive editors, associate editors, technical editors, and authors. This has been a lot of work for all of us, and I greatly appreciate all your efforts—especially the tremendous contributions by Stacie Hughes and Knut-Andreas Lie. Welcome to Vladimir Alvarado and Roberto Aguilera, who will join SPE Journal as executive editors in January 2019. I know you will do a great job! The work is critical in sorting through all the ideas that are out there, so we can guide SPE members to the most valid technology.

This issue presents 30 new papers in six categories as follows.

Reservoir Simulation And Reserve Evaluation. Alpak and Vink introduce a variable-switching method for mass-variable-based reservoir simulations. A link is established at the numerical-solution level between natural- and mass-variable formulations. The method can be used to rapidly evaluate different primary solution variables on problem nonlinearity and solver efficiency.

Chen et al. apply a global-search distributed-Gauss-Newton optimization method and integrate it with a randomized-maximum-likelihood method for uncertainty quantification of reservoir performance. The authors find that hundreds of data-conditioned realizations can be generated in parallel within 20 to 40 iterations.

Yang et al. present a case study of a 4D coupled reservoir/geomechanics simulation of a high-temperature/high-pressure naturally fractured reservoir. The simulation reveals large potential conductivity reductions for natural and hydraulic fractures during the course of field production. Stress-induced changes are predicted to compromise integrity of poorly cemented wellbores.

Sorek et al. propose a strategy for designing wells to maximize productivity even when wells are not drilled in the minimum direction. They find that as long as the multiple-transverse-fracture horizontal-well design drains the same simulated rock volume, a well with acute-angle fractures can perform as well as a well with fracture planes perpendicular to the well axis.

Garcia and Heidari develop a resistivity model that incorporates quantitative directional connectivity and tortuosity for enhanced assessment of hydrocarbon reserves. Using cuttings from different rock types, the method is applied to two carbonate formations. Quantification of rock fabric and pore-space conductivity improve estimation of hydrocarbon saturation by 43% compared with conventional methods.

After revisiting the volumetric equation, Ma presents a parametric method for assessing hydrocarbon volumetrics. The paper discusses how use of new equations can quantify inaccuracy of projections made from the classical method, especially for heterogeneous, low-quality, and tight reservoirs.

Flow in Wellbores and Fractures. Yoshida et al. model downhole temperature in a horizontal well that intersects multiple fractures. The study shows that injection makes temperature in a fracture lower than the geothermal temperature, even after 1 month of shut-in. This affects temperature interpretation during production.

Luo et al. describe a semianalytical model for horizontal-well productivity with pressure drop along a wellbore. The productivity index of a well is shown to depend on the interaction between horizontal-well conductivity, penetration ratio, and Reynolds number.

Tang et al. develop a fully implicitly coupled wellbore/reservoir simulator to characterize transient liquid loading in horizontal gas wells. A modified drift-flux model is proposed to predict the flow-regime transition for different pipe inclinations from vertical to horizontal.

Fan et al. study the onset of liquid-film reversal in upward-inclined pipes. They present a mechanistic model to predict critical gas velocity that is based on liquid-film reversal in a stratified flow. Other models are reviewed that predict critical gas velocity.

Wang and Sharma discuss estimating unpropped fracture conductivity and fracture compliance from diagnostic-fracture-injection tests. They propose use of a “normalized system stiffness plot” to establish the existence of residual facture width during fracture closure, to estimate fracture compliance (stiffness), and to infer unpropped fracture conductivity.

Dejam et al. present an analytical expression for shear dispersion of a solute transporting in a rough-walled fracture through a matrix. Three levels of surface roughness are considered. For all roughness geometries, an increase in either Péclet number or relative roughness leads to an increase in dispersion.

Drilling. Amipally amd Kuru compare the influence of shear viscosity and elastic effects on settling velocity of particles in viscoelastic fluids (HPAM solutions). Settling velocity values can be overestimated by factors of 14 to 50 if elasticity is not considered.

Hegde et al. compare algorithms for real-time rate-of-penetration optimization in drilling using data-driven models. On the basis of their simulations, data-driven models can be used for real-time drilling despite their computational constraints. The simplex algorithm provides the best tradeoff in terms of rate of penetration and computational efficiency.

Liu and Abousleiman investigate the effects of mudcake and multiporosity/multipermeability on the evolution of safe-drilling mud weight. Natural fractures narrow the safe-drilling mud-weight window by degrading rock strength and by facilitating compressive pressure invasion. Mudcake expands the safe-drilling window by generating compressive radial stress on the wellbore wall and impeding hydraulic-pressure invasion.

Bizhani and Kuru assess the equivalent sandbed roughness and the interfacial fraction factor in hole cleaning with water in a fully eccentric horizontal annulus. Sandbed roughness is found to be variable and several times greater than the mean-particle size. Depending on the surface area of the bed at the interface, the interfacial friction factor can be significantly different from the average friction factor.

Phase Behavior and Souring. Yassin et al. visually studied nonequilibrium interactions between carbon dioxide and oil at pressures up to 2,000 psi and temperatures up to 122°F. Results suggest that the combination of density-driven natural convection and extracting/condensing flows enhances dissolution of supercritical carbon dioxide into the oil phase.

In describing the phase behavior of confined hydrocarbons, Liu et al. compare the Peng-Robinson equation of state (including a capillary pressure model) with engineering-density-function theory. The work illustrates that assuming homogeneous distributions of nanopores may not appropriately predict phase behavior under nanoconfinement.

Mehana et al. use molecular simulations to study density of oil/gas mixtures. Results suggest that intermolecular Coulombic and induced dipole interactions might not be the key to understanding oil/CO2 density behavior. In contrast, molecular size of the gas seems to play an important role.

Ferreira et al use a packed-bed bioreactor to test five biocides in controlling biological souring in mature oil wells. Neem oil and 3,5-dimethyl-1,3,5-thiadiazinane-2-thione are the most effective in controlling sulfate-reducing bacteria.

Pore-Level Interactions and Relative Permeabilities. Ayirala et al. study water ion interactions at crude-oil/water interfaces during low-salinity waterflooding in carbonates. The study integrates results from different measurement techniques to demonstrate the importance of both salinity and certain ions (magnesium and calcium) on crude-oil-droplet coalescence and oil-phase connectivity.

Frank et al. perform direct numerical simulation of flow on the basis of pore-scale images using the phase-field method. A Helmholz free-energy-driven, thermodynamically based diffuse-interface method is used to simulate numerous advecting surfaces, while honoring interfacial tension. The methodology rigorously considers flow physics by directly acting on pore-scale images of rocks without re-meshing.

Rabinovich provides analytical corrections to core relative permeability for use in low-flow-rate simulation. The derivation is performed using power-law averaging, assuming log normally distributed core permeability. Given a core that has been characterized by conventional high-rate coreflooding experiments, the current method gives a fast correction for low-rate applications.

Ren et al. examine the interplay between permeability retardation and capillary trapping of rising carbon dioxide in storage reservoirs. At any given time, the total CO2 accumulated by permeability hindrance is greater than that accumulated by capillary trapping. However, over long times, the contribution from capillary trapping can approach that from permeability hindrance.

Enhanced Oil Recovery. Mahmoud studies the effect of chlorite clay-mineral dissolution on oil recovery from sandstones during flooding with diethylenetriaminepentaactic acid. This chelating agent sequesters iron, increases water-wetness, and improves oil recovery during flooding.

Torrealba and Johns present partition-coefficient relations for improved equation-of state descriptions of microemulsion phase behavior. Surfactant partition coefficients are combined with a chemical-potentials equation-of-state model to predict phase behavior when excess phases are not pure.

De Loubens et al. numerically models unstable waterfloods and tertiary polymer floods of viscous oils. They propose that hysteresis of relative permeability may be needed to properly account for behavior when polymer floods are applied after waterflooding of viscous oils.

Liu et al. propose an inversion method (based on the Levenberg-Marquardt algorithm) to derive relative permeability curves during polymer flooding. The paper discusses the impact on relative permeability for errors in polymer-solution viscosity, residual resistance factor, inaccessible pore volume, and polymer adsorption.

Erincik et al. study reductions in residual oil saturation by polymer flooding with a high salinity after polymer flooding with a low salinity. Surprisingly, substantial reductions in residual oil saturation occur during the high-salinity polymer flood. At present, an explanation for this result is not clear, and additional experiments are needed to determine whether the effect will be of practical value during field applications of polymer flooding.

Irani and Gates present the third paper of a series of papers that discuss subcool control in steam-assisted-gravity-drainage (SAGD) producers—specifically focusing on the efficiency of subcool trapping in the Nsolv process. Subcool is the temperature difference between the injected butane and produced fluids.

Randy Seright, SPE J. Executive Editor,
New Mexico Institute of Mining and Technology