Please enable JavaScript for this site to function properly.

- Boolean operators
- This
**OR**that

This**AND**that

This**NOT**that - Must include "This" and "That"
- This That
- Must not include "That"
- This -That
- "This" is optional
- This +That
- Exact phrase "This That"
- "This That"
- Grouping
- (this
**AND**that)**OR**(that**AND**other) - Specifying fields
**publisher:**"Publisher Name"**author:**(Smith OR Jones)

Wang et al. propose carbon dioxide temperature-field models in a wellbore and fracture to calculate transitions of fluid-phase states and variations of fluid thermal-physical parameters during fracturing with CO
_{2}. With elapsed time during fracturing, fluid temperatures in the wellbore and fracture are predicted to drop rapidly, while pressures rise gradually.

Mao et al. propose a robust and efficient calculation of the
*β* coefficient in the Forchheimer equation for use in high-velocity flow in proppant-filled fractures. They argue that the product of
*β* and proppant-pack permeability falls within a limited range, thus improving predictability of pressure drops.

Awoleke et al. present an empirical model and a semi-empirical model of fracture conductivity in the presence of damaged proppant packs. Both models matched experimental data adequately and are advocated as a first approximation for short-term fracture conductivity in field hydraulic fractures.

Using the theory of linear-elastic fracture mechanics, Mehrabian develops an analytical solution for a wellbore in an isotropic elastic medium when drilled inclined to a general state of 3D far-field stress. The wellbore can be attached to an arbitrary number of straight and axially aligned fractures. Application of the analysis may aid understanding of lost-circulation events.

Yang et al. use simulation to assess how a horizontal well’s lateral direction affects productivity, reserves, and economics in tight oil and gas reservoirs. For cased-hole completions in gas reservoirs, the study concludes that horizontal wells should be drilled in the direction of the maximum horizontal stress (i.e., longitudinal) if permeability is greater than 1.5 md and drilled transverse to this direction for less-permeable formations. For oil reservoirs, wells should be drilled in the transverse direction for permeability between 50 nd and 5 md.

Awada et al. present a work-flow procedure for identifying interference using data acquired during a typical multi-well-pad-production scheme. The intent is to help production analysts diagnose interference and avoid common pitfalls.

Marongiu-Porcu et al. model interwell fracture interference for Eagle Ford shale-oil reservoirs. The work is directed at modeling pressure depletion and associated stress properties over time.

Wu et al. introduce a unified model for gas transfer in nanopores of shale-gas reservoirs. The paper concludes that slip flow can be ignored if pore radius is less than 2 nm and pressure is less than 1 MPa. Knudsen diffusion is only important if pore radius is greater than 50 nm and pressure is less than 1 MPa. Surface diffusion is important if pore radius is less than 25 nm and pressure is less than 5 MPa.

Lee et al. describe a comprehensive simulation model of kerogen pyrolysis for the in-situ upgrading of oil shales. The model is applied to the Shell In-situ Conversion Process in the Green River formation.

Using cores from two Middle Eastern carbonate reservoirs, Nasralla et al. confirm that low-salinity waterflooding shifted wettability toward water-wet and improved oil recovery, even if calcite was not dissolved.

Telmadarreie and Trivedi use micromodel studies to visualize displacement of a 30,000-cp crude by CO
_{2} foam and polymer-enhanced foam. The paper is directed at understanding displacements in carbonate reservoirs after solvent floods were applied.

Using simulation studies, Lee et al. examine the impact of spherical/radial/linear flow on foam propagation and sweep efficiency. They argue that foam-propagation distance is very sensitive to injection rate and pressure for high-quality, strong foams, but less so for low-quality, strong foams.

Kumar and Okuno present a new algorithm for characterizing multiphase behavior for solvent-injection simulation. The algorithm improves reliability of predictions from the Peng-Robinson equation of state by use of binary-interaction parameters.

Nourozieh et al. experimentally measured viscosities and densities of Athabasca-bitumen/toluene mixtures at temperatures up to 190°C and pressures up to 10 MPa. The Bij method was found to predict mixture viscosities most reliably.

Using thermodynamic and geomechanical analyses, Irani and Gates examine the boundary between drained and undrained zones during steam-assisted-gravity drainage (SAGD). They conclude that the sheared zone should be contained by the drained zone for all SAGD operations, and the drained assumption is valid to analyze permeability enhancement ahead of the steam front.

Hashmi and Firoozabadi describe asphaltene deposition and removal in metal capillaries. They found that dodecyl benzene sulfonic acid removed asphaltene deposits much more effectively than toluene.

Li et al. present two papers on biodiesel that was produced from waste cooking oil. The first paper describes the chemical composition and formulation of an emulsion that is suitable for use as a drilling fluid, and provides an initial economic analysis. The second paper evaluates rheology, formation damage, environmental compliance, and other properties of the fluid.

Seales et al. investigate the occurrence of hydrate-bearing sediments off the east coast of Trinidad and Tobago. Although conditions are favorable for formation of gas hydrates in this region, considerable uncertainties surround the thickness and location of the gas-hydrate stability zone.

Liu and Reynolds develop an augmented Lagrangian approach for biobjective optimization of well-control problems during waterflooding, with bounded constraints. In a second paper, the same authors extend this analysis to include nonlinear state constraints.

For gas wells producing under boundary-dominated flow, Stumpf and Ayala define a hyperbolic window in which the constant-b assumption in the Arps model is valid. They show that type-curve and straight-line analysis techniques can be used to explicitly determine reservoir properties, including original gas in place.

Sousa et al. use the Green’s functions technique to solve the case of an infinite, homogeneous, isotropic gas reservoir being produced through a single vertical well represented by a line source with wellbore storage and skin. The solution does not consider non-Darcy flow effects.

Miranda et al. present a new uniform-flux solution (based on the Green’s function method) for modeling the pressure-transient behavior of a restricted-entry well in anisotropic gas reservoirs.

Zhang et al. use a high-frequency asymptotic solution of the diffusivity equation to history match, perform uncertainty analysis, and provide a performance assessment for a shale-gas reservoir.

Using a clustering method associated with an optimization procedure, Compan et al. describe a semiautomatic methodology to determine the relative permeability rock types from experimental relative permeability data. The method significantly decreased data scattering for groups of relative permeability curves.

New Mexico Institute of Mining and Technology