é um caminho que desperta crescente interesse, quer seja por sua real utilização nos espaços formais de ensino, quer seja pelos trabalhos de pesquisa em ensino apresentados à comunidade. O uso crítico e referenciado das TIC pode colaborar com uma aprendizagem mais efetiva e potencializar oportunidades de uma educação para a emancipação e a autonomia, especialmente quando conjuga qualidade acadêmica e tecnologias livres. Nesse sentido, destacamos a importância da realização de atividades experimentais significativas em aulas de física mediadas por tecnologias educacionais livres que apresentam, ao mesmo tempo, qualidade, flexibilidade de uso e baixo custo, de modo que sejam compatíveis com a realidade educacional brasileira. Para contem-+ Video analysis with the free software Tracker for the laboratory in Physics education: parabolic motion and Newton's second law

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A laboratory study has been conducted on the use of chemical plugs, instead of conventional mechanical packers, to isolate water and gas-producing zones in horizontal wells. Results of experiments using horizontal wellbore models, consisting of PVC pipes internally lined with sand, indicate that slumping of the chemical plug could be avoided if the plug were spotted in a viscous brine pill. Of the three chemicals tested, a monomer, a polyacrylamide, and a plastic, only the plastic plug had a sufficiently high holding pressure. Research is being continued using a full-scale horizontal wellbore model.

TX 75083-3836, U.S.A., fax 01-972-952-9435. ProposalCurrently, the study of naturally fractured reservoirs represents a constant-growing technology because of the high amount of this type of behavior in many reservoirs worldwide. Therefore, for an efficient exploitation is necessary to adequately model them, so a more realistic fracture-matrix flow behavior can be obtained and identified. However, by inspecting some well pressure tests, anomalous slope changes during a matrix-controlled flow period are observed. This behavior does not follow the one described by a dual porosity model.Throughout the years, the pressure transient behavior of naturally fractured reservoirs has been extensively studied. Customary, dual porosity models have been widely utilized to describe the flow behavior taking place in the fracture/matrix system of naturally fractured reservoirs. However, a remarkable flaw of these models is their assumption of homogeneous matrix properties through the whole system. Recently, pseudosteady-state and transient-state triple porosity models have been introduced to take into account the existence of two domains in the matrix with different properties and one domain in the fracture net. There is no flow between the two matrix domains. On a semilog plot of pressure versus time, three parallel straight lines are observed when one domain has lower storativity and higher interporosity flow coefficient. Well pressure analysis for such systems was conducted using the conventional method or semilog type-curve matching.In this study, pressure derivative is applied to triple porosity reservoirs so their typical characteristics and fingerprints are reported. A technique to analyze pressure and pressure derivative data without using type-curve matching is also provided. This technique uses characteristics lines, characteristics points and features found on the pressure and pressure derivative plot to obtain analytical expressions for a practical estimation of permeability, skin and the fundamental parameters of such systems. The proposed methodology was successfully verified by its application to field data cases and simulated pressure data.

Proposal Because their great efficiency in producing higher flow rates per unit pressure drawdown, horizontal wells have currently become a popular alternative for the development of hydrocarbon fields around the world. So far, most of the introduced correlations to estimate the productivity index for these wells have shown certain differences among their results. This does not allow us to properly establish which one of them provides the closest value to the actual one, since there is no evidence of a trustable enough reference point. Throughout the years, several investigations for the determination of horizontal-well productivity index have been carried out. These researches have been focused on the determination of steady-state solutions for the above-mentioned parameter, therefore, a diverse number of correlations have been introduced. These correlations have been presented by such very well-known researchers as Giger, Borisov3, Merkulov 2, Renard & Dupuy2–5 and Joshi2–5. They are mainly based upon complex analytic solutions which may have some uncertainties when applying them. This paper proposes an improved steady-state correlation to calculate productivity index for horizontal wells and evaluates the most commonly used existing correlations to estimate this parameter by using numerical simulation. Besides that, a sensitivity analysis on the influence of the variation of each variable in the existing and proposed models was carried out. The analysis was conducted by generating a synthetic drawdown test by means of a commercial reservoir simulator. Using the pressure derivative curve, a time range where steady-state behavior takes place was defined. Then, a simulation was performed with the purpose of determining the pressure distribution in the reservoir within that range of time. This allows us to estimate the horizontal-well productivity index for any drainage radius. More than 500 simulation runs were performed to estimate the results obtained by the improved correlation introduced in this work and the existing ones. Several plots of productivity index versus each one of the model variables were constructed for comparison purposes. It was observed that Joshi s correlation matches well with the simulated results. However, the proposed correlation provides much better results than those provided by Joshi's within a very wide range of variation of the parameters involved in the different correlations. Introduction Throughout the years, several investigations on the determination of the productivity index for horizontal wells have been developed. These researches have been focused on finding a steady-state flow solution which has resulted in different correlations. These correlations were developed by such well-known researchers as Giger2, Borisov 3, Merkulov2–5, Renard & Dupuy2–5 and Joshi2–5. However, there are remarkable differences among the results they provide which does not allow us to clearly establish which one matches closely the actual value since not accurate comparison point has been given. In this paper, based on numerical simulation, we define which existing correlation is the most appropriate for the estimation of the productivity index in horizontal wells. The limitation or application range for them is presented, as well. For this purpose, we chose a practical and very useful way to perform our computations: Numerical simulation. Because their popular use in the oil industry around the globe, we combined the power of PEBI grids, Eclipse 300 and Eclipse Office to develop our work. PEBI grids have provided a very convenient way to numerically represent horizontal wells, faults and pinchouts1.

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A technical feasibility study of a polymer-augmented waterflood process in San Francisco Field indicated that this enhanced oil recovery process might be commercially feasible. Since the feasibility study used hypothetical polymer properties, laboratory measurements of specific commercially available polymers were required. The experimental program was divided into three phases.A screening program to reduce the number of candidates. Basic fluid rheological data and quality were developed. For each polymer candidate, four polymer concentrations in three different salinity brines were prepared. Screen Factor tests, Filtration Ratio and viscosity measurements were obtained for each solution. The results were compared to select the best polymers for further testing.Core flooding experiments of the selected candidates. Parameters describing the rock polymer interactions (polymer adsorption and residual resistance factor) were developed. The polymer flow properties (viscosity versus shear rate) developed in the first phase were tuned to match the core flow experiments in a reservoir simulation model.A thermal aging study to verify that the selected polymer does not degrade significantly at reservoir temperature over time. This was a long-term test (six months duration). This paper describes the application of the procedures described in the American Petroleum institute publication RP63, dated June 1, 1990, "Recommended Practices for Evaluation of Polymers Used in Enhanced Oil Recovery Operations", and a case history of laboratory testing of polymer flood candidates. Introduction San Francisco Field produces from the Caballos Formation and is located in the Middle Magdalena Valley basin in Colombia, South America. San Francisco was discovered in 1984 and has been in production since that year. It is a heterogeous faulted anticline at 3000 ft depth. The initial pressure was 1100 psi and reservoir temperature is 45 C. Initial bubble point pressure was 950 psi. The API gravity of the oil varies from 23 to 28 degrees. 1 Caballos Formation is subdivided in Upper Caballos and Lower Caballos. Upper Caballos has a porosity that ranges between 12 to 23% and a permeability range between 20 md and 2000 md. Lower Caballos has a porosity variation between 9 to 19% and a permeability range from 10 md to 1500 md. 2 San Francisco Field is currently ungoing secondary recovery by water flood. A technical study showed that a polymer augmented waterflood process might be commercially feasible. The study used hypothetical polymer properties. To tune the study and to define the proper polymer for the process, a laboratory testing program was designed. Samples of water soluble polymers designed for use as mobility control agents in Enhanced Oil Recovery (EOR) operations and currently available in commercial quantities were solicited from several vendors. Experimental Materials and Methodology The samples of polymer tested, with some of the main properties, are listed in Table 1.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn general, a horizontal well is more productive than a vertical well, due to the fact that there is a larger area of contact with the reservoir and that there is less pressure drop per unit of length in the production section.