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.

Thermal recovery methods made possible the production of heavy oil fields considered non-commercial with conventional methods of recovery. In this context, steam injection has proved to be a major cost-effective alternative for increasing the heavy oil recovery. Steam Assisted Gravity Drainage (SAGD) is one of the field proven improvements. It uses two horizontal wells with the steam injector above the producer, which stays at the base of the reservoir. Sweeping the reservoir with the growth of a steam chamber. The variations on conventional SAGD involving non-condensable gases show a new trend. Numerical results suggest that after a certain period of time operating only with steam is effective to inject only inert gas. In this process the steam chamber keeps growing even after the steamflood is stopped. The purpose of the gas injection is to maintain the reservoir pressure elevated to keep the oil production. The cumulative steam oil ratio has a downward trend, yielding a reduction in the project costs. In this paper, a numerical study of the SAGD method in field scale is conducted. The reservoir model is simulated with properties obtained from a Brazilian onshore field. The methodology used involves an investigation of the main parameters that influence the application of the method and, according to a sensitivity analysis. The aim is to determine the best time to start gas injection looking to maximize NPV. A commercial software is used to simulate the injection of nitrogen after steamflooding the reservoir in order to obtain the results that are used to perform the sensitivity analysis. It was verified that the steam injection rate and the bottom hole pressure are decisive parameters to be considered. The simulations show that the nitrogen injection after a determined period of time of continuous steam injection reflects in a reduction in the order of 40% of the steam oil ratio. However, the cumulative oil production is almost the same when compared with the conventional SAGD.

The understanding of single and multiphase flow behavior in porous media has been improved with the development of in situ saturation measurement techniques such as X-ray Computed Tomography (CT), mainly in specialized core analysis. On the other hand, effective experimental designs are necessary to advance knowledge on operations of Water Alternating Gas (WAG) and Carbon Capture and Storage (CCS) projects. The present study addresses the determination of petrophysical properties concerning fluid storage and displacement in carbonates by using CT images taken during core flooding runs. Eight displacement experiments were carried out in long core to analyze N2 and CO2 flooding under reservoir conditions (from 700 to 7000 psi) at temperatures of 22°C and 65°C. A carbonate core sample of 5 cm diameter by 76 cm long with porosity of 15% from a carbonate outcrop analogous to Brazilian pre-salt reservoir rocks was used in the displacement tests. The mixing of CO2 and brine was a key experimental procedure to evaluate the CO2 trapping. The parameters of porosity, permeability, distribution of initial non-wetting phase, irreducible brine saturation, trapped non-wetting phase saturation, displacement effectiveness and the effect of saturation history were investigated during drainage-imbibition cycles similar to those in the WAG process. Values for Land trapping coefficients were evaluated from on-line X-ray CT scan images. The trapped non-wetting phase saturation ranged from 8 to 16 percent for both N2 and CO2 floods. The results reveal that trapped saturations are higher for higher pressures and higher temperatures. Cross-section images show the enlargement of pore spaces induced by brine-CO2 flooding with a consequent increase of the trapping capacity. Porosity and permeability changed after a CO2 injection, along with the observed formation of short wormholes. In addition, some degree of dissolution of the rock was verified and solid particles of carbonate salts were collected at the outlet of CO2-brine runs. The results obtained emphasize the importance of using high-resolution saturation imaging to provide the main parameters for the experimental evaluation of CO2-WAG processes in carbonates. Introduction Carbon dioxide (CO2) flooding has been considered as one of the most important processes for enhancing oil recovery (EOR) from carbonate reservoirs since the 1980's [1]. Its use, though, is most of the time limited by the availability of an economic source. In the Brazilian pre-salt reservoirs, e.g., Tupi field, the solution gas contains a high proportion of CO2 [2]. The re-injection of the produced CO2 in this case represents the solution of two problems at once. It solves the discard problem, which is of growing environmental concern, at the same time it provides the resource for improving the difficult oil recovery. Both EOR and environmental processes demand new studies covering the application of WAG injection and the safety of geological storage of CO2. The alternating injection of water and gas was conceived in order to compensate the counter tendencies of gas rising upward and water falling downward within the reservoir by ‘breaking-up’ the continuous slug of gas into smaller slugs by alternating water banks [3]. On the other hand, injecting water with miscible gas reduces the instability of the gas/oil displacement, improving the overall sweep efficiency.

The present study aims to deepen the investigations of a previous study, in order to rank which variables are more critical to CO2-WAG process Enhanced Oil Recovery and which injection schemes and parameters are more effective when capillary pressure and relative permeability are adapted to Brazilian pre-salt scenario. The methods compared were Water Alternating Gas (WAG) and Hybrid Water Alternating Gas, considering saturation dependent hysteresis modeled through Larsen-Skauge model. A detailed and reliable Equation of State for oil with high pressure, and unusual natural carbon dioxide content (8.4%) was developed based in published data to match rheology and swelling measurements. The model was a small scale water-wet carbonate/stromatolite reservoir model with the same set of relative permeability and capillary pressure with hysteresis and entrapment data were modeled as basis for pre-salt Brazilian reservoir data. The optimization were analized including hysteresis and entrapment data from the literature. The reservoir model well constraints for each strategy were meant to be as realistic as possible, the recovery was optimized using an optimization tool, and the cases were analyzed comparatively. The most important effects were ranked and the best injection scheme and parameters were determined for the studied case in order to clear conclusions about the importance of fluid and petrophysical mechanisms for miscible final oil recovery. Among a series of petrophysical phenomena needing further investigations on their influence on oil recovery, relative permeability is of critical importance. Nonetheless, its representation in reservoir simulation is quite a complicated task. It may incorporate hysteresis effects (at least three different models that can be used), and it may present three-phase behavior (extrapolated from two phase relative permeability experimental data). Just like relative permeability hysteresis, there are at least four different models available to represent three phase relative permeability. In the present work, only Larsen and Skauge model was addressed. As a consequence of all complexities involved, for some subtle changes in the injection scheme, such as the injector operating restraints, make recoveries sensitive to hysteresis and passive of improvement. Simulations indicated that an incremental oil recovery of about 11%, in both WAG and HWAG schemes when hysteresis was considered compared to no-hysteresis case. Optimization of well operating conditions and constraints (bottom-hole pressure of producers and injectors, gas and water rate limits) has a significant effect on oil recovery and production rates.

In the WAG recovery method, alternating the injected fluids promotes changes in the saturation of the porous media. Associated with these changes, two phenomena occur, which are very relevant to the movement of fluids in the rock: (1) capillary trapping of CO 2 during an imbibition process, and (2) hysteresis in the relative permeability curves. Information regarding CO 2 trapping and cyclic hysteresis effects is key for predicting the behavior of the carbonate reservoirs subjected to water alternating gas (CO 2 -WAG) and CO 2 storage processes.The objectives of this study were divided in two parts. First was to investigate, at laboratory scale, the dependence of trapped (residual) gas saturation and gas relative permeability hysteresis on several fluid/rock properties in two-phase flow. The second was to investigate, also at laboratory scale, the hysteresis effects on the gas and water relative permeabilities in three-phase flow. To this end, tests were conducted on carbonate samples that were considered to be heterogeneous. The samples used were coquinas from outcrops that are analogous to pre-salt samples, coming from the Morro do Chaves formation, in the Sergipe-Alagoas Basin, Brazil. The mineralogical composition, pore geometry and petrophysical properties of samples similar to those used in this study were characterized by thin sections and X-ray Computed Tomography.In this study, an experimental methodology was developed to characterize carbonate rocks in such a way as to allow adequate investigation of the WAG method at laboratory scale.Monitoring of the saturation distributions during the displacement tests was conducted through X-ray Computed Tomography (CT), along with detailed procedures for obtaining material balances. The methodology is presented in two steps that include, first, the assembly of an apparatus (A) for studying in-situ capillary trapping of CO 2 in a long sample (A) (76 cm) and, second, the assembly of another apparatus (B) to conduct the three-phase hysteresis test on a short sample (B) (21 cm). The samples were prepared, and the tests followed the procedures considered to be standard for the proposed studies. To investigate the trapping of the non-wetting phase (gas) in two-phase flow (gas-water), drainage and imbibition displacements were carried out under different levels of pressure (700 to 7000 psi) and temperature (22°C and 65°C) in order xvi to evaluate the influence of the rock/fluid properties on the residual saturation of the non-wetting phase (gas) in the porous media. To investigate the hysteresis of water and gas relative permeabilities in three-phase flow, sequences of multiphase drainage and imbibition displacements were carried out in porous media saturated with oil and irreducible water.The results of the investigation on the amount of the non-wetting phase trapped saturation show that the combined effects of increased viscosity and density of the gas in high pressure and temperature conditions increase the maximum gas trapped saturation. The Land trapping coefficient...