In-situ upgrading (IU) is a promising method of improved viscous and heavy oil recovery. The IU process implies a reservoir heating up and exposition to temperature higher than 300°C for long enough time to promote a series of chemical reactions. The pyrolysis reactions produce lighter oleic and gaseous components while a solid residue remains underground. In this work, we developed a numerical model of IU based on lab experiences (kinetics measurements and core experiments) and validated results applying our model to an IU test published it the literature. Finally, we studied different operational conditions searching for energy-efficient configurations.
In this work, two types of IU experimental data are used from two vertical-tube experiments with Canadian bitumen cores (0.15 m and 0.69 m). A general IU numerical model for the different experimental setups has been developed and compared to experimental data, using a commercial reservoir simulator framework. This model is capable to represent the phase distribution of pseudo-components, the thermal decomposition reactions of bitumen fractions and the generation of gases and residue (solid) under the cracking conditions.
Simulation results for the cores submitted to 370°C and production pressure of 15 bar, have shown that oil production (per pseudo-component) and oil sample quality were well-predicted by the model. Some differences in gas production and total solid residue were observed with respect to laboratory measurements. Computer-assisted history matching was performed using an uncertainty analysis tool on the base of the most important model parameters. In order to better understand IU field-scale test results, the Shell’s Viking pilot (Peace River) was modeled and analyzed with proposed IU model. The appropriated grid-block size was determined and calculation time was reduced using the adaptive mesh refinement technique. The quality of products, the recovery efficiency and the energy expenses obtained with our model were in good agreement with the field test results. Also the conversion results (upgraded oil, gas and solid residue) from the experiments were compared to those obtained in the field test. Additional analysis was performed to identify energy efficient configurations and to understand the role of some key variables, e.g. heating period and rate, the production pressure, in the global IU upgrading performance. We discuss these results which illustrate and quantify the interplay between energy efficiency and productivity indicators.
For waterflooding in argillaceous reservoirs, the injection water needs to be carefully designed to avoid formation damage by clay swelling and migration. Common methods of achieving this are compatibility tests of injection water with formation water and rocks and injectivity tests. However, such tests are often not practical nor even possible due to the limited availability and prohibitive cost of obtaining actual reservoir cores. The objective of this work was to develop a cost-effective method to evaluate injectivity that does not require the use of reservoir core. In this study, a novel coreless injectivity method was developed and validated. The method utilizes field-produced drill cuttings to make synthetic core plugs, which are universally available during well drilling and commonly considered as waste. A specially designed cleaning process was performed for the drill cuttings. They were then wet compressed with a high-pressure hydraulic press and dried in a constant-humidity oven to make core plugs with standard dimensions. Drill cutting plugs prepared in this way can then be used for injectivity tests as an alternative to actual reservoir core plugs. The routine core analysis revealed that, although sedimentary structures were lost, the drill cutting plugs preserved the mineralogy and maintained comparable porosity and permeability to the reservoir plugs. To validate the representativeness of the formation damage tendencies of the drill cutting plugs, water injectivity tests were carried out on both preserved reservoir cores and compressed drill cutting cores, using simulated injection water with successively lower salinities. The results showed that injectivity loss as indicated by increasing pressure drop was consistent with both types of cores. The "coreless injectivity evaluation" technique can be applied for argillaceous reservoirs with formation damage concerns. It is a cost-effective and viable technique for evaluating water injectivity when reservoir cores are unavailable.