Carbon dioxide (CO2) is considered one of the main gases that cause global warming. In this perspective, its injection in aquifers and oil and gas reservoirs has been a possible alternative to reduce its emission in the atmosphere. An alternative strategy in which CO2 is used efficiently in the Oil Industry is the Carbonated Water Injection (CWI), where the carbon dioxide is injected through the reservoir dissolved in the brine, eliminating problems of gravitational segregation and low sweeping efficiency present in other gas injection methods. Once injected, the fluid may react with the carbonate rock and inducing their dissolution, causing changes in the petrophysical properties of the rock. This work investigated changes in the average porosity of carbonate samples from Brazilian reservoir through a dynamic flow test with enriched brine with 100% CO2 injection under high pressure and high temperature conditions and simulating a region around the face of the injector well, with an injection pressure of 8,500 psi, a temperature of 70 °C and a flow rate of 2cm3/min. The core-flooding experimental setup includes two coreholders arranged in series with samples confined in its interior, which are swept by X-ray Computed Tomography (CT), taking measurements of average porosity data. The results showed that there was dissolution in the sample assembled in the first coreholder since the porosity had increased, while in the second, no significant alterations of the porosity were observed (around 8.5% of its initial value). This observation can still be confirmed by the analysis of the dissolved moles, which exhibit behavior similar to the porosity, indicating that some minerals actually suffered dissolution from the injection of carbonated brine.
Some carbonate reservoirs are known for their high CO2 content in oil. One possibility to handle this gas without environmental problems is to reinject it into the reservoir. Injection of carbonated water has been drawing attention because it is an advantageous technique when compared to gaseous CO2 injection, due to its improvement in mobility in the reservoir. The objective of this study is to evaluate the phenomenon of dissolution and precipitation during carbonated water injection in carbonate rocks. These effects are identified by analyzing the porosity variations through X-ray computer tomography images and permeability profile, determined indirectly by pressure transducers that measured the differential pressure by the fluid at the inlet and outlet of the core holders. The Coreflooding test were carried out with two core holders in series to represent a near region at the reservoir by the injection of brine saturated with 25% of CO2 in reservoir samples, composed of dolomite, calcite and clay. The test were performed using the following reservoir conditions of 8,500 psi at 70°C. Based on the experimental data provided by CT images, it can be seen that the core porosity increases or decrease during carbonated water injection due to coexistence of dissolution (increase of porosity) and precipitation (decrease of porosity) along the samples. These phenomena are observed in regions with high heterogeneity in porosity. In addition, the mineralogy of the cores is composed by three minerals, which influence in the capacity of reaction with carbonated water. For the experiment, the core placed in the core holder one presented a porosity increase and the second one decreased. On the other hand, the permeability showed a significant increase for both cores, it is believed that, the injection promoted a preferential way flow (wormhole) that affected considerably the permeability of the rock. The novelty of the investigation is that the experiments were carried out using Brazilian pre-salt carbonate reservoir rocks with mineralogy composed basically by dolomite, calcite and clay. Also, experimental work was performed at reservoir operational conditions.
During the development stage of a petroleum field, one important decision is to define the schedule for drilling the wells. Several general rules were listed for light and heavy oils. However, these rules are not always applicable and it may be important to use simulation models to test and choose the schedule. This paper consists of the development, implementation, and application of two different algorithms for optimization of wells drilling schedule. The first algorithm seeks, for each period, which well brings the best economic output. Once this well is selected, the second period of time is tested considering the remaining wells and this procedure is repeated until the last well. The second procedure is based on the reduction of search space where random schedules are generated and the best results maintained for the subsequent generation of scenarios, only allowing the wells to be drilled in the period that produced the best values of the objective function in the previous step. This procedure is repeated until each well converges to the period that results in the best economic return. Both algorithms were tested in two synthetic fields, based on the characteristics of offshore heavy oil and high average permeability reservoirs. To generate a benchmark for the solutions, a large amount of random schedules were tested and a normal distribution for net present values was generated. Both algorithms can be applied in any type of reservoirs, resulting in a very time consuming process in the cases where simulation time is very high. The results from both algorithms lead to net present values higher than at least 95% of the values from random schedules. For both cases, economic results were significantly better than those found for selecting strategy using wells ranking based in economic indicators, which is a common procedure. Both algorithms are also easy to implement and they can be inserted in a cycle of automated or assisted optimization process.
An accurate understanding of the matrix-fracture mass transfer is fundamental to the modeling of fractured reservoirs. Nevertheless, the difficulty in an appropriate representation of this process comes from the fact that matrix and fracture interact in a particular manner depending on physical mechanisms as capillary imbibition. Capillary imbibition is considered through wettability in several mass transfer formulations (also called transfer functions) as the main mass driving force between matrix and fracture. This paper provides simulation results of waterflooding in two different scales of fractured models: Core plug models and extended models (a quarter of 5-spot), aiming to evaluate the influence of wettability and flow rate alteration on the matrix-fracture mass transfer. The methodology applied is based on sensitivity analyzes of wettability and flow rates scenarios, comparing parameters involved in matrix-fracture mass transfer: capillary continuity, fluid transfer rate, and hydraulic conductivity of the fracture system. The methodology is divided into three main parts. Initially, single-porosity models with an induced longitudinally fracture at laboratory scale are simulated, to obtain accurate models in terms of representative responses for wettability and flow rate changes. Secondly, dual-porosity/permeability models are constructed also at laboratory scale to analyze and compare answers to mass transfer. As a third stage, extended models are created attempting to analyze the impacts of sensitivity parameters of mass transfer on a larger scale. Results show that the increase of rock preference for water leads to highest oil recovery factors at low and high-water injection rates, benefiting mainly from the water spontaneous imbibition. Notably, the spontaneous imbibition in these cases is more considerable in low-rate scenarios, due to its larger contact time with water and rock. However, the increment on production may not be economically feasible, because of the long time (high pore volumes injected) needed to get this increase. In contrast, intermediate and oil-wet scenarios exhibit low oil sweep and displacement efficiency at low and high-water injection rates. Accordingly, these scenarios reach water breakthrough quickly and exhibit a less accentuated tendency to water saturation alterations if compared with a water-wet scenario. Results from single-porosity models show a good agreement between the water saturation distributions along the length and the effect of the induced fracture, validating its use. Results also reflect the effects of the fractured porous media formulations at both model scales as well as the effects of the shape-factors. In a numerical simulation study, this work shows the importance of close interaction between the wettability, flow rate changes, and the parameters that control matrix-fracture mass transfer. At last, the significance of these sensitive parameters is also demonstrated.
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