Summary Water is usually considered insoluble in the oil phase; however, at the temperatures typically encountered in the steam-injection process, water may have higher than 40 mol% solubility in the oil phase. On a mass basis, experimental results from the literature indicate water solubility as high as33%. We developed a practical and robust algorithm for a water/oil/gas three-phase flash calculation. The algorithm is based on the well-developed vapor/liquid two-phase flash-calculation algorithm and avoids trivial or false solutions commonly found in multiphase flash calculations. We also developed a fully compositional thermal reservoir simulator, considering water/oil mutual solubility, to study the effect of water-in-oil solubility on oil recovery in the steam-injection process. A simulation study shows that when water is soluble in the oil phase, it may increase oil recovery appreciably. We also found that the oil fluids should be characterized with at least three components for accurate compositional thermal reservoir-simulation study. Introduction Steam injection is used widely as an improved-oil-recovery method for the production of heavy oil and many light-oil resources. Conventional reservoir simulation of the steam-injection process simplifies the computations by ignoring water solubility in the oil phase. However, as temperature increases, water solubility in the oil phase increases significantly. Griswold and Kasch studied water/oil mutual solubilities at elevated temperatures. Their data show that for a 54.3°API naphtha, the solubility of water in oil is 16.18 mol% at431.6°F; for a 42°API kerosene, the solubility of water in oil is 34.97 mol% at507.2°F; and for a 29.3°API lube oil, the solubility of water in oil is 43.44mol% at 537.8°F. Nelson also showed that water solubility in oil is as high as42 mol% at 540°F. Heidman et al. showed that the solubility of water in liquidC8 is 38.7 mol% at 500°F. Glandt and Chapman obtained up to 33.3 wt% of water dissolved in crude-oil mixtures and analyzed its effect on oil viscosity. This high solubility will dramatically change the viscosity, density, and thermal expansion of the hydrocarbon phase and, consequently, affect the production performance. Therefore, a rigorous and efficient multiphase flash algorithm is needed to evaluate the phase equilibrium of water/hydrocarbon systems. Also, fully compositional thermal reservoir simulations, which consider water-in-oil solubility, are necessary to evaluate the extent to which the water-in-oil solubility affects oil recovery in the steam-injection process.

Activities in developing tight oil and gas reservoirs, such as the Barnett shale and the Bakken formation, have grown tremendously in recent years. Economic production of these unconventional resources relies heavily on advanced completion technology such as horizontal wells with multi-stage hydraulic fracture stimulations. Unlike single-stage fractured vertical wells, multi-stage fractured horizontal wells (MFHW) exhibit a unique flow regime, compound formation linear (CFL) flow, which consists of linear flow in the formation toward the collective hydraulic fractures after interference has occurred between neighboring fractures. This flow regime can easily be mistaken for a reservoir-boundary (or compartmentalization) effect in production analysis. Such a misinterpretation will result in incorrect reservoir property estimates and long-term production forecasts. This paper applies log-log reciprocal rate derivative plots to identify and analyze flow regimes of MFHW wells producing under constant bottomhole pressure. It is observed that the CFL straight line slope in the reciprocal rate derivative plot depends on the ratio of fracture length over fracture spacing but is not sensitive to reservoir permeability. As a result, the CFL slope can be used to diagnose fracture stimulation effectiveness.

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TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractThe world still contains tremendous heavy oil resources. Ever-increasing energy demand requires more attention to be paid to harvesting all hydrocarbon resources, including heavy oil. The use of thermal processes has proven by far the most effective approach in producing heavy oil. This paper proposes a practical steam stimulation strategy for heavy oil development using horizontal wells. In the proposed process, steam is cyclically injected through a horizontal well pattern to heat near wellbore reservoirs, and after a period of cyclic steam stimulation, one of the pattern wells is converted to a steamflooding well and the other pattern well is converted to a production well.Through 3D reservoir simulation, this paper compares production performance of the proposed strategy with conventional cyclic steam stimulation (CSS), steamflooding (SF), and steam-assisted gravity drainage (SAGD).A sensitivity analysis is also conducted to study the effect of oil viscosity and reservoir permeability on horizontal well production performance under different production strategies.

It is widely accepted that unconventional resources hold enormous reserve potential. However, complex fluid flow physics and completion/stimulation practices pose a unique challenge in estimating reserves or making long-term production forecast for these unconventional reservoirs, as traditional methods are most often not applicable. This paper proposes the application of a probabilistic reservoir simulation workflow to provide realistic range of production forecasts with successful application in the Bakken unconventional tight oil reservoir. First, geomodels are constructed and ranked. Then, key static and dynamic uncertainty parameters are identified for the subsequent history-matching study (with each of the geomodel realizations) that provides not only production forecast for individual wells but also parameter ranges for experimental design (DoE) for field-level prediction. Then, DoE simulations are conducted to construct proxy equations that are used in Monte-Carlo simulations to generate Low-BTE-High response S-curves for the field-level models. Finally, based on these S-curve results, Low-BTE-High deterministic reservoir simulation models are constructed to generate corresponding long-term production forecast profiles for full-field development and optimization.