Pseudo-Component, Thermal Reservoir Simulation Study of A Proposed, Low Pressure, Steam-Assisted Gravity Drainage Pilot Project in Northeast Alberta

2011 ◽  
Author(s):  
Michelle Uwiera ◽  
Michael Robert Carlson ◽  
Claes T.S. Palmgren
Keyword(s):  
Simulation Study ◽  
Reservoir Simulation ◽  
Pilot Project ◽  
Low Pressure ◽  
Gravity Drainage ◽  
Thermal Reservoir ◽  
Steam Assisted Gravity Drainage ◽  
Pressure Steam

Modelling Steam-Assisted Gravity Drainage Process in the UTF Pilot Project

1991 ◽  
Author(s):  
A.L. Siu ◽  
L.X. Nghiem ◽  
S.D. Gittins ◽  
B.I. Nzekwu ◽  
D.A. Redford
Keyword(s):  
Pilot Project ◽  
Gravity Drainage ◽  
Steam Assisted Gravity Drainage

Reservoir Simulation Study of Water-in-Oil Solubility Effect on Oil Recovery in Steam Injection Process

2005 ◽  
Vol 8 (06) ◽  
pp. 528-533 ◽  
Author(s):  
Shanqiang Luo ◽  
Maria A. Barrufet
Keyword(s):  
Oil Recovery ◽  
Simulation Study ◽  
Reservoir Simulation ◽  
Water Solubility ◽  
Steam Injection ◽  
Production Performance ◽  
Oil Viscosity ◽  
Thermal Reservoir ◽  
Injection Process ◽  
Flash Calculation

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.

scholarly journals Numerical Simulation Study on Steam-Assisted Gravity Drainage Performance in a Heavy Oil Reservoir with a Bottom Water Zone

Energies ◽  
2017 ◽  
Vol 10 (12) ◽  
pp. 1999 ◽  
Author(s):  
Jun Ni ◽  
Xiang Zhou ◽  
Qingwang Yuan ◽  
Xinqian Lu ◽  
Fanhua Zeng ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Study ◽  
Heavy Oil ◽  
Bottom Water ◽  
Gravity Drainage ◽  
Oil Reservoir ◽  
Steam Assisted Gravity Drainage ◽  
Water Zone ◽  
Heavy Oil Reservoir

Reservoir Simulation of Hydrogen Sulfide Production During a Steam-Assisted-Gravity-Drainage Process by Use of a New Sulfur-Based Compositional Kinetic Model

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 080-093 ◽  
Author(s):  
Simon V. Ayache ◽  
Violaine Lamoureux-Var ◽  
Pauline Michel ◽  
Christophe Preux
Keyword(s):  
Hydrogen Sulfide ◽  
Kinetic Model ◽  
Reservoir Simulation ◽  
Steam Injection ◽  
Laboratory Scale ◽  
Gravity Drainage ◽  
Production Data ◽  
Oil Sand ◽  
Oil Companies ◽  
Steam Assisted Gravity Drainage

Summary Steam injection is commonly used as a thermal enhanced-oil-recovery (EOR) method because of its efficiency for recovering hydrocarbons, especially from heavy-oil and bitumen reservoirs. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection and occurring in the reservoir. In particular, these reactions can lead to the generation and production of the highly toxic and corrosive acid gas hydrogen sulfide (H2S). The overall objective of this paper is to quantitatively describe the chemical aquathermolysis reactions that occur in oil-sands reservoirs undergoing steam injections and to provide oil companies with a numerical model for reservoir simulators to forecast the H2S-production risks. For that purpose, a new sulfur-based compositional kinetic model has been developed to reproduce the aquathermolysis reactions in the context of reservoir modeling. It is derived from results gathered on an Athabasca oil sand from previous laboratory aquathermolysis experiments. In particular, the proposed reactions model accounts for the formation of H2S issued from sulfur-rich heavy oils or bitumen, and predicts the modification of the resulting oil saturate, aromatic, resin, and asphaltene (SARA) composition vs. time. One strength of this model is that it is easily calibrated against laboratory-scale experiments conducted on an oil-sand sample. Another strength is that its calibration is performed while respecting the constraints imposed by the experimental data and the theoretical principles. In addition, in this study no calibration was needed at reservoir scale against field-production data. In the paper, the model is first validated with laboratory-scale simulations. The thermokinetic modeling is then coupled with a 2D reservoir simulation of a generic steam-assisted gravity drainage (SAGD) process applied on a generic Athabasca oil-sand reservoir. This formulation allows investigating the H2S generation at reservoir scale and quantifying its production. The H2S- to bitumen-production ratio against time computed by the reservoir simulation is found to be consistent with production data from SAGD operations in Athabasca, endorsing the proposed methodology.

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