Thermal Simulation

Key Takeaways

• The SAGD thermal simulation challenge is accurately modeling the steam chamber growth and heat transfer at the chamber edge — in SAGD simulations, the steam chamber expands at rates of meters per year from the injection well, and the steam-heated bitumen drains to the producer under gravity; the accuracy of the simulation depends critically on correctly modeling heat transfer at the advancing steam-cold oil interface: heat is transported from the hot steam to the cold bitumen by conduction (diffusion of heat through the rock matrix and oil), and the rate of heat transfer controls how quickly the bitumen viscosity is reduced and how fast the drainage front advances; simulations that under-resolve the grid near the steam front (using coarse grid blocks that average the steep temperature gradient across the front) will mispredict the steam chamber growth rate, the drainage rate, and the steam-to-oil ratio; fine gridding near the steam front is required for accuracy but dramatically increases computational cost, creating the fundamental grid resolution trade-off that SAGD thermal simulation must manage.
• Steam quality and heat content are explicitly tracked in thermal simulations because they determine both injection efficiency and heat delivery — steam injected for EOR is characterized by its dryness fraction (quality): 100% quality steam is dry saturated steam; below 100% it is a mixture of steam and hot water; the heat content of the injected fluid (the enthalpy per unit mass) depends on both the temperature (which determines saturation pressure) and the dryness (which determines the fraction of latent heat content); as steam moves from the surface injection point through the wellbore and into the reservoir, heat losses to the wellbore tubulars, cement, and surrounding formation reduce the steam quality, so that steam entering the formation may have 70% quality when surface measurements indicate 80%; thermal simulations include a wellbore heat loss model that predicts the steam quality entering the reservoir as a function of injection rate, wellbore geometry, insulation, and formation thermal properties; incorrect wellbore heat loss modeling causes the simulation to predict different steam quality injection than actually enters the formation, biasing the simulated steam chamber growth rate and recovery performance.
• Relative permeability curves for thermal simulation must account for the temperature dependence of interfacial tension and wetting at elevated temperatures — the relative permeability to oil and water (the functions that describe how easily each phase flows at a given saturation) changes with temperature because: surface tension between oil and water decreases with temperature, reducing the capillary pressure that immobilizes residual oil; wetting behavior of rock surfaces changes with temperature, potentially improving drainage efficiency; oil viscosity-to-water viscosity ratio changes dramatically (heavy oil becomes much less viscous relative to water at steam temperatures), affecting the mobility ratio and thus the displacement efficiency; conventional isothermal relative permeability measurements on core at ambient temperature are inadequate for thermal simulation and must be replaced with temperature-dependent relative permeability measurements made at multiple temperatures between ambient and steam temperature, or with correlations that adjust the ambient-temperature curves for temperature effects; obtaining representative thermal relative permeability measurements is one of the most challenging aspects of laboratory characterization for thermal EOR projects.
• In-situ combustion (fireflood) simulation adds reaction kinetics to the thermal model for the most complex EOR process — in-situ combustion injects air into the reservoir and ignites the heavy oil fractions in place, creating a combustion front that moves through the formation and generates heat from the burning of residual coke deposited ahead of the front; the combustion products (CO2, CO, water, N2, and light hydrocarbons from thermal cracking) drive the mobilized oil ahead of the front to producers; simulating this process requires the thermal simulator to include chemical reaction kinetics (the rates at which the coke deposits form and burn, the rate of hydrocarbon cracking to generate the coke, and the rates of combustion reactions between fuel and injected oxygen) in addition to the thermal and multiphase flow equations; the reaction kinetic parameters must be measured in laboratory combustion tube experiments on actual reservoir core and crude oil samples and are highly specific to each crude oil-reservoir combination; in-situ combustion simulation is the most computationally intensive and parameter-rich of all EOR simulation methods, reflecting the complexity of the simultaneous combustion, thermal, and multiphase flow processes in the reservoir.
• Thermal simulation of SAGD is used for well pair optimization, facility design, and production forecasting with increasing sophistication — the commercial thermal simulators (CMG STARS, Eclipse THERMAL, UTCHEM-SAGD) can model individual SAGD well pairs in high resolution or full field arrays of hundreds of well pairs in lower resolution, each approach suited to different questions; individual well pair models with fine geological detail are used for optimizing well spacing, perforation intervals, and steam injection strategy for a specific geological setting; field-scale models with simplified geology are used for long-term production forecasting and facilities planning; the accuracy of all these models depends on the quality of the geological inputs (reservoir thickness, heterogeneity, cap rock integrity) and the laboratory measurements (thermal properties, viscosity-temperature relationships, relative permeability) used to populate the simulation parameters; history matching thermal simulations to actual SAGD well performance data (steam injection rates, oil production rates, temperature profiles from observation wells) calibrates the model parameters and improves confidence in the production forecasts used for reserve reporting and investment decisions.