Executive Summary


This April issue of SPE Journal brings 27 papers categorized under six topics.


Thermal Recovery Methods

Pang et al. introduce a new method, called expanding-solvent steam and gas push (ES-SAGP), to develop thin heavy-oil reservoirs. The authors use 3D simulation to research the effectiveness of injecting noncondensate gas and vaporizable solvent together with steam into the steam chamber during steam-assisted gravity drainage (SAGD). They demonstrate that the new technique not only sharply enlarges the volume of the steam chamber, but also significantly improves the sweep efficiency and the ultimate recovery.

Shirdel et al. present algorithms and signal-processing techniques for interpreting fiber-optic measurements for quantitative steam-injection-flow profiling. The new algorithms rely on a variety of physical principles and are applicable to both transient and steady-state flow. Resulting interpretations from two injectors are validated using 11 short-offset injector observation wells and three reservoir observation wells.

Xiong et al. present a series of 2D numerical simulations of the MacKay River and Dover reservoirs in western Canada to investigate the influence of pressure differences on SAGD recovery. The authors also establish a predictive mathematical model and suggest that pressure difference may be a new optimizable factor in designing SAGD recovery processes.

Gallardo and Deutsch introduce an approximate physics-discrete simulator to model the steam-chamber evolution in SAGD. The underlying simulation algorithm is formulated using graph theory, simplified porous-media flow equations, heat-transfer concepts, and ideas from discrete simulation. The simulator is sufficiently efficient to be applied over multiple geostatistical realizations to support decisions in the presence of geological uncertainty.

Keshavarz et al. propose a new analytical model approach for SAGD, in which the problem of heat transfer is directly solved for a stationary source of heat at the base of the steam chamber where oil production occurs. Distribution of heat along the moving interface is then estimated depending on the geometry of the steam chamber. The authors seek to clarify discrepancies between various previous models and demonstrate that their new model gives reasonable agreement with fine-scale numerical simulations.

Mohan et al. study the conservation-of-species equation for solvent vapor-extraction processes and develop an improved model equation that differentiates between the velocity within the oil and the velocity at the interface, which can be solved to obtain a profile of the solvent in oil. With the improved velocity profiles, the authors explain recent observations that the oil rate depends on the height of the pay zone and not on its square root. The new approach can also be used to predict how the oil/vapor interface evolves with time.


Hydrates

Almenningen et al. investigate the rate of gas recovery from methane-hydrate-bearing sediments. Key findings are that the maximum rate of recovery is only to a small extent affected by the magnitude of the pressure reduction below the dissociation pressure, and that hydrate saturation directly affects the rate of recovery, with intermediate hydrate saturations giving the highest initial recovery rate.

Yoneda et al. consider gas production from offshore gas-hydrate-bearing sediments. The authors present a multiphase-coupled simulator designed to study the settlement of the seabed and frictional stresses induced along the production casing by depressurization and dissociation of hydrates, as well as gas generation and thermal changes.

Singh et al. propose an analytical model to estimate relative permeability of gas and water in a hydrate-bearing porous medium without curve fitting or use of any empirical parameters. The model is derived by imposing momentum balance with the steady-state form of the Navier-Stokes equations for gas/water flow. The new model is validated against a number of laboratory studies and shown to perform better than most empirical models over a full range of experimental data.

Yuan et al. establish a history-matched model and use this to study the gas productivity from a hydrate reservoir in the Eastern Nankai Trough.


Compositional Modeling and Phase Behavior

Salehi et al.  develop new methods for upscaling of compositional simulation. The authors first introduce a method to compute upscaled phase-molar-mobility functions that account for subgrid effects caused by compressibility and by fine-scale variations in absolute and relative permeability. Then, phase behavior is upscaled by assuming instantaneous equilibrium on the fine scale, which gives upscaled thermodynamic functions that represent differences in component fugacities and account for nonequilibrium effects at the coarse scale.

Mancilla-Polanco et al. map the phase behavior of heavy-oil/propane mixtures for temperatures ranging from 20 to 180°C and pressures up to 10 MPa, and report yield data measured using a blind-cell apparatus. The authors develop pressure/temperature and pressure/composition phase diagrams, as well as ternary diagrams, and study the ability of volume-translated Peng-Robinson equations of state to match the experimental measurements.

Will et al. discuss how rigorous compositional analysis can be coupled with analytical well-performance relationships for reservoirs with complex fluid systems. The authors demonstrate that it is possible to predict the decline behavior of individual fluid constituents for a variety of gas/condensate-reservoir systems characterized by widely varying richness and complex multiphase-flow scenarios.

Torrealba et al. present a novel equation of state for microemulsion-phase behavior that accounts for changing micellar curvatures. The new equation improves phase-modeling capabilities and eliminates the use of net-average curvature in favor of a more-physical definition of characteristic micelle length.


Low and Ultralow Permeability Systems

Cronin et al. propose a recovery mechanism for enhanced oil recovery by solvent injection that is entirely based on diffusion-dominated transport. The authors develop a proxy model assuming first-contact miscibility to provide rapid estimates of oil recovery from primary production and from solvent huff ‘n’ soak ‘n’ puff processes in ultratight oil reservoirs.

Sun et al. study and develop a predictive model to describe the effect of pressure-propagation behavior on production performance in coalbed-methane recovery.

Chai et al. develop a new gas-transport model to characterize single-component real-gas flow in nanoscale organic and inorganic porous media by modifying the Bravo model. A straight capillary tube is first characterized by a conceptual model consisting of a viscous-flow zone, a Knudsen-diffusion zone, and a surface-diffusion zone; it is then scaled up to a bundle-of-tubes model by considering roughness, rarefaction, and real-gas effects.

Civan reviews and modifies methods for determining nanodarcy gas permeability and other parameters of naturally and hydraulically induced fractured-shale formations on the basis of pressure transmission of cure plugs, drill cuttings, and crushed samples.


Sand Production

Wang et al. present a 3D numerical study to explain why the onset of sand production in gas wells differs from that in oil wells. Onset of sanding observed at higher compressive stresses for gas wells is explained by sand strengthening by evaporation of water, which is not observed in oil wells. When non-Darcy effects are considered, sand-production rates are lower than for Darcy flow.

Wang and Sharma present a fully coupled poro-elasto-plastic, 3D sand-production model for predicting sand production around openhole and perforated wellbores in weakly consolidated formations. Sanding criteria are based on a combination of shear failure, tensile failure, and compressive failure from the Mohr-Coulomb theory and strain hardening/softening. The model not only explains the mechanism behind different cavity shapes, but also predicts the cavity shape that will be formed under specific conditions.


Fracturing and Fractured Systems

AlTammar et al. investigate the initiation and propagation of fractures in the presence of multiple layers with different mechanical and flow properties. In particular, experiments reveal a clear tendency for induced fractures to avoid harder bounding layers, resulting in fracture deflection and kinking, and that fractures induced in thin layers tend to propagate parallel to the bounding surfaces.

Szymczak et al. study numerically how low-pH reactive fluids affect calcite-cemented fractures in gas-bearing shale formations and show how the morphology of the emerging flow paths strongly depends on the thickness of the calcite layer.

Teng and Li develop a semianalytical model to characterize the pressure-transient behavior of a finite-conductivity, partially penetrating inclined fracture. The model discretizes the fracture into small panels, and each panel is treated as a plane source. Fluid flow in the fracture system is solved numerically, whereas fluid flow in the matrix is described analytically using Green’s functions.

Xu et al. develop a unified-state model to simulate the flow and thermal behaviors of different energized fracturing fluids (foams, carbon dioxide, nitrogen) and investigate the changes of fluid properties from the wellhead to the toe of a horizontal wellbore.

Li and Zhang discuss the effectiveness of carbon dioxide as an alternative fracturing fluid. The authors systematically examine water and carbon dioxide fracturing and compare their performance on the basis of a rigorously coupled geomechanics and fluid-heat-flow model.

Peng et al. discuss how temperature variations influence the rheological properties of fracturing fluids and the reaction rates of rock and acid in acid/hydraulic fracturing. The authors present a semianalytical model for calculating the heat transfer in a wellbore under transient state, considering heat conduction in the cement sheath and forced convection in the tubing.

Teng and Li develop a semianalytical model to evaluate the performance of a vertical well with an orthogonal fracture. The well production is divided into three stages: the first stage, when the well produces oil with the initial fracture; the second stage, during which the well is shut down for the refracturing treatment; and the third stage, when the well produces oil with both the initial fracture and the refracture.


Acknowledgments. It is my pleasure to announce that Dr. Reza Fasihi (University of Calgary) was promoted to executive editor. With Reza onboard, SPE Journal now has three excellent executive editors who will be in charge of  the journal’s scientific quality and profile over the next 3 years. I would also like to welcome our newest associate editor, Dr. Bill Bailey (Schlumberger), to the editorial board. As usual, I end my executive summary by thanking all those who have written, reviewed, copy edited, and prepared the papers in this issue.

Knut-Andreas Lie, SPE J. Executive Editor,
SINTEF Digital/NTNU