Rock samples from a Middle East carbonate retrograde condensate gas field were studied to determine their relative permeability to gas and condensate curves. We have emphasized the determination of condensate minimum flowing saturation-or critical condensate saturation-and the reduction of permeability to gas in the presence of immobile condensate saturation.A ternary pseudoreservoir fluid of methane/pentane/nonane made it possible to work in simulated reservoir conditions with a greater flexibility for experimental procedures. The initial water saturation equaling that in the reservoir was restored. The results of the gas-condensate system indicate that the critical condensate saturations are high (the average value is 36% PV) and that the reduction of permeability to gas is higher than for a standard gas/oil system. Also presented are the details of the experimental procedures, the fluid characteristics, the results, and a discussion.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA full analysis of the problem of coupling two independent industrial simulators, a reservoir simulator and a steady-state network simulator, has been performed.
Steam injection has been recognized as an efficient process for recovering hydrocarbons from heavy oil and bitumen reservoirs. However, it is now well known that the steam injection induces chemical reactions within the reservoir, called aquathermolysis and yielding acid gases. Hydrogen sulfide (H 2 S) being highly toxic and highly corrosive, even at low concentrations, it is of major importance to forecast H 2 S production. However, until now, there are only very few publications relating reservoir simulations of steam injection processes accounting for thermal and compositional effects in a chemically reactive context.The proposed paper relates a work focused on H 2 S production forecast during a SAGD process from aquathermolysis experimental results and simulation. After a description of the aquathermolysis experiments, the simplified sulfur-based kinetic model deduced from the experimental results is presented. This sulfur-based kinetic model has been used to build a thermo-kinetic component-based model usable in a compositional and thermal reservoir simulation. A simulation of the experimental aquathermolysis reactor being run for validating the thermo-kinetic model, the simulation results of H 2 S production and oil SARA composition versus time are shown to be in good agreement with the experimental results.Then, the thermo-kinetic modeling has been input in a cross-section model designed for simulating a SAGD process. The H 2 S production results were found to be consistent with published field data.The work related in the paper contributes to provide a new insight to the simulation of H 2 S production by aquathermolysis, through the presentation of a simplified modeling of the aquathermolysis reactions, and the description of a methodology for building an EOS (Equation Of State) model compatible with the reactive model.The followed approach is shown to be usable for forecasting H 2 S production due to an aquathermolysis phenomenon during a steam injection process.
Steam injection for enhanced oil recovery induces chemical reactions within the reservoir, called aquathermolysis, which can lead to in-situ H 2 S generation and to H 2 S production at the wellhead. H 2 S production risk is particularly acute in oil sand reservoirs because they contain sulfur-rich bitumens. To forecast H 2 S production risk in these conditions, a workflow based on geochemical investigation and reservoir simulation has been developed. It relies on (1) a quick estimate, using a dedicated technique, of sulfur content and thermal reactivity of a large number of reservoir samples to map the H 2 S production risk over the field; (2) carrying out more time-consuming aquathermolysis experiments on oil sand samples selected from step 1, to define a kinetic model for H 2 S generation based on atomic sulfur thermal reactivity; (3) transforming this sulfur-based kinetic model into a molecular SARA components-based kinetic model, usable in a compositional and thermal reservoir simulator; (4) simulating the EOR process with the reservoir simulator to calculate H 2 S/oil ratio at the wellhead.The geochemical methodology has been applied to four oil sand samples from Athabasca. The results have underlined that sulfur content and sulfur thermal reactivity of oil sands measured with the quick estimation technique are well correlated with the amount of H 2 S produced from the more lengthy aquathermolysis experiments. Moreover, it was shown that the sulfur in the oil sand, when distributed among Saturates, Aromatics, Resins, Asphaltenes, Solid matrix and H 2 S, as a function of time and temperature of aquathermolysis, can be interpreted in terms of sulfur-based kinetic model. This model can be used for a calculation of H 2 S generation upon aquathermolysis at field production temperature and time scale, thus for estimating the H 2 S production potential.As detailed in another SPE paper (Barroux et al., 2013), reservoir simulation has been used to simulate a SAGD process in a generic 2D model of an Athabasca oil sand. One main finding of this study has been that the H 2 S/oil ratio at the wellhead appears to depend mainly on the stoichiometry of the kinetic model.
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