Thermal recovery processes are widely applied for heavy oil and bitumen production. Unique thermal properties of water and water steam allowed efficient reduction of extremely high viscosities by several orders of magnitude and made a vast heavy oil and bitumen reserves production technically and economically feasible. Steam effect on heavy oil and bitumen in traditional reservoir engineering for a long time has been considered as physical only, i.e. viscosity reduction, improved flow parameters, distillation effects, emulsification, etc. However multiple laboratory studies and field observations suggest that initial oil undergoes chemical alteration and gases such as H2S and CO2 could be produced in increased quantities. Estimation of H2S and CO2 production potential is important due to considerable corrosivity of these gases, associated environmental, economical and other issues. In this study a practical approach has been developed to simulate and forecast H2S and CO2 production during thermal recovery using common reservoir simulation tools. First, analytical data was matched and then chemical reaction had been implemented to the sector model. Steam Assisted Gravity Drainage (SAGD) was chosen to demonstrate the concept of suggested approach and analyze the results. Generated gases were considered to be soluble both in water and oil. The importance of accounting for gas solubility in water was demonstrated and discussed. Simulated volumes of H2S and CO2 are in good agreement with that observed in the field applications of steam assisted recovery methods.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIncreasingly, the industry is aware of the need to improve field development planning decisions with more rigorous risk analysis. A key is to have technology and work processes supporting the complex evaluation of projects as a whole, i.e. from subsurface to processing with economics, while preserving physical fidelity and interdependent uncertainties. This paper will illustrate how an integrated stochastic approach with scenario analysis, sensitivity analysis, and Monte Carlo simulation assisted an asset team to understand overall project uncertainties and sensitivities for a large gas project. This understanding gave a better basis for the planning decisions.The richness and speed of the integrated stochastic approach is compared with more conventional case study analysis. The latter requires manual iteration to investigate how variations of input variables as e.g. reservoir properties impact reserves and production. It is followed by manual input to the economic model and manual analysis.Outputs presented from hundreds of simulations from the integrated stoachastic approach include distributions and histograms of original fluids in place, cumulative production, plateau period, net present value, production rate, discounted cash flows, and rates of return etc. Correlation coefficients between input uncertainties and output uncertainites indicate which input uncertainties give the major contribution to the output uncertainties. This helps the asset team to focus on the important factors for major decisions, and use less time on the less important issues.

The Gullfaks Field is located in the Norwegian Sector of the North Sea, block 34/10, and currently has the capability of producing more than 70,000 Sm3/d of oil (440,000 stb/d) from three CBS platforms. The reservoir sands comprise shallow marine to fluvial sediments of the Cook Formation, Statfjord Formation and Brent Group, ranging in age from Early to Middle Jurassic. Water injection is the major drive mechanism for maintaining reservoir pressure above bubble point. Development wells have confirmed a complicated structural picture with numerous faults beyond seismic resolution, causing major impacts on predicting field reserves and flow patterns. Reverse faulting in an area of predominantly normal faulting further emphasises the structural complexity. Complex geology along with field performance after water breakthrough resulted in several changes in the initial development strategy. Production from the highly productive Tarbert and Statfjord sands was accelerated in order to compensate for the loss of production from the Lower Brent sands caused by sand production after water breakthrough. Development of complex Ness and low productivity Cook sands have recently commenced. Gravel packing, implemented in the Upper Brent field development, provided sand control and increased production rates. Various types of chemical sand control are currently being evaluated and tested in the field. Lowering pressure in gravel packed wellbore region below bubble point may increase the production rates even further. Following advances in drilling technology, highly deviated/horizontal wells improve recovery and accelerate field development by combining production from several reservoirs in one single well. A test programme for surfactant and WAG flooding has been implemented on the field. Other EOR methods, such as gel and polymer flooding, are currently being investigated for potential use.

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