The surface steam injection is the most common enhanced oil recovery (EOR) process used in heavy oil production. Nevertheless, there are limitations due to the heat loss for deep reservoirs and for offshore fields. Downhole steam generators (DHSG) are a new technology that opens a new path for recovery of heavy oil from deep reservoirs, offshore fields and extreme cold regions. Downhole steam generators eliminate the need for surface steam distribution systems, for flowlines and wellbore steam strings. The outflow of DHSG generators are a mixture of steam and flue gas. The main objective of this paper is to investigate the recovery dynamics of steam injection combined with flue gas at lab scale to recover a 16.14°API heavy oil from a sandpack. Superheated steam at 170°C was co-injected at flow rates between 5 and 4.5 ml/min (cold-water equivalent) with flue gas at flow rates between 150 and 340 ml/min in a linear cell built for the continuous injection of steam. From the results it can be asserted that co-injection reduces by 10% the amount of steam needed for an equivalent recovery. That translates in cutting steam generator costs on a per barrel of oil produced basis. The results of the tests addressed in this study provide: 1) The gas helps to keep the pressure behind the front more stable; 2) the co-injection of steam with flue gas accelerates the start of oil production when compared with steam injection alone; 3) Results indicates recovery factors up to 79%. The results favors DHSG as a promising technology for enhanced oil recovery of heavy oils, mainly for offshore fields or reservoirs at great depth.

Enhanced oil recovery methods must be improved continuously to provide higher recovery factors for the new fields under development in a globally competing market. CO 2 injection processes in carbonate rocks involve reactions between acid brine and the rock. These interactions promote petrophysical changes in the rock structure due to calcite dissolution or precipitation. Lab experiments in saturated coquina samples were carried out to better understand the effects on porosity by CO 2 injection. X-ray Photoelectron Spectrometer (XPS) was used to analyze the surface chemistry of the rock sample for elemental composition measurement. X-Ray Micro-CT and Mercury Injection Capillary Pressure (MICP) were carried out to calculate mean porosity in the rock sample. X-Ray scans were run for each pore volume injected. The results show that dissolution should be considered when supercritical CO 2 is injected in the reservoir. This process has relevance for project design, risk analysis, economic evaluation and reservoir behavior forecast.

The surface steam injection is the most common enhanced oil recovery (EOR) process used in heavy oil production. Nevertheless, there are limitations due to the heat loss for deep reservoirs and for offshore fields. Downhole steam generators (DHSG) are a new technology that opens new pathways for recovery of heavy oil from deep reservoirs, offshore fields and extreme cold regions. DHSGs eliminate the need for surface steam distribution systems, for flowlines and wellbore steam strings. The outflow of DHSG generators are a mixture of steam and flue gas. In the present work, an experimental study was developed in a linear steam injection cell to better understand how the injection of steam combined with flue gas contributes to the recovery process and to the possible reduction in the required amount of steam injected. The experimental apparatus used in this study was designed and built at Unicamp for flooding of steam or steam combined with other fluid. The entire study was conducted at the lab scale with a heavy oil originated from the Potiguar Basin and from the Espírito Santo Basin. In the experiments, steam was injected at flow rates of 5 ml / min when pure and 4.5 ml / min when co-injected with flue gas. The gas flowrate varied between 150 and 800 ml / min. The results show that: 1) the coinjection of steam with flue gas accelerates the start of oil production when compared with steam injection alone; 2) The gas helps to keep the pressure behind the front and make it more stable; 3)The improvement on the steam/oil ratio shows that co-injection of steam with flue gas is beneficial to replace a significant amount of steam; 4) Recovery factors when co-injecting gas is greater than when using pure steam, with an increasing trend for the recovery factor when the volume of gas injected increases and 5) a favorable variation occurs in the quality of the oil produced during the recovery history with co-injection.

More than half of the world's oil reserves are located in carbonate reservoirs, and in the Brazilian pre-salt context, contain high amounts of CO2. Due to environmental issues related to CO2 emissions, one of the solutions is the CO2 re-injection into the reservoir. The processes of CO2 injection in carbonate rocks involve reactions between the acidic brine and the rock. These interactions promote changes in the rock structure due to calcite dissolution or/and precipitation.The objective of this work was to investigate in pore scale using the technique of x-ray microtomography, the alterations of the porous medium through the injection of high salinity carbonated brine. With the development of two experiments at 65 °C and 2000 psi, the experiments will represent for two different flow rates the dissolution patterns for the coquine rock and find the regions where the changes occurred in the porous medium.The methodology developed in this work was applied to two coquine rocks with high presence of microporosity. Porosity and permeability data were obtained before and after the experiments using a porosimeter and a permeabilimeter. The measured laboratory values were compared to the permeability (obtained from differential pressure) and porosity (through X-ray microtomography images). Microtomography images were analyzed using a three-phase segmentation technique, which separates macropores, micropores and grain phases. For the first experiment we used a flow rate of 0.1 cm 3 /min and for the second experiment a flow of 0.5 cm 3 /min. The two flow rates were selected to simulate different regions in the reservoir.The laboratory results show an initial loss of injectivity in the system with reduction and subsequent increase of permeability. After several pore volumes injected, dissolution patterns in the form of wormholes were found. The use of mapping through 2D histograms for the pre-and post-dissolution images showed the occurrence of precipitation and dissolution in the entire sample, although the reactions are stronger in the vicinities of the injection face. The produced fluids results showed that there is a good agreement between the porosity values measured in laboratory and through ion chromatography.