fax 01-972-952-9435. AbstractRecent exploration efforts in the Campos Basin, offshore Brazil, have resulted into important discoveries of what is known as "offshore heavy oil" (API gravities below 18 and reservoir viscosities above 20 cp). Actually, these accumulations have been known since the beginning of the development of the Basin, in the 80s, but they were never given a chance of development due to the technology challenges involved. The maturation of lighter oil fields, associated with recent technology developments (1,2,3), has boosted the interest for these heavy oil resources set aside for many years. This paper describes the simulation model building process, the difficult task of assigning scarcely sampled rock and fluid properties, the uncertainty study and the use of quality maps for placing the wells. Simulations results have shown the importance of the well footage and its effectiveness in contacting the reservoir rock.

Open hole completion is, nowadays, the most used completion technique in horizontal wells. Many times, for operational reasons, such completions can take many days, sometimes months, to be executed. This problem leads to a questioning about what happens to the invaded area during such exposition to the drilling fluid. To answer such question, an experimental study of invaded area aging was performed. Such procedure consisted in real-time CT-scan measurement of the invaded area by the water based polymeric drill-in fluid filtrate. The formulation used is very common at the Campos Basin, Brazil. The tested samples were submitted to in situ conditions (pressure and temperature), during all the experiment time, which took about one year. It was verified that the invaded filtrate area for this drill-in formulation increased about 40% in the first 34 hours, maintaining this level during the rest of the experiment. Besides, analysis done with a Scanning Electronic Microscope (SEM) in one of the tested samples, showed that the solids and salts from the drilling fluid were only present in the filtrate invaded area. Introduction Since the last decade, a considerably increase in horizontal well demand has happened. It is due to the advantages brought by this kind of well, for reservoir drainage and productivity. Also, the completion technique most used for such wells is the open-hole one, for operational and financial reasons. The increase of open-hole completions leaded to the development of new specific fluid systems for drilling horizontal wells named drill-in fluids (DIF). These fluid systems present behaviour of both drilling and completion fluids. Some characteristics of such fluids are1:they are specially designed for drilling through reservoir zones;Its additives lead to formation damage minimization, increasing well productivity;the mud cake provides an efficient control of the invaded area during drilling;they are biodegradable and present low toxicity. Nowadays, the water based polymeric drill-in systems are the most used. Their formulation is based on xantan gum (viscosifier), polymer derived form starch (filtrate controller), magnesium oxide (alkalinizer), KCl or NaCl (clay inhibitor) and the bridging agent, that can be NaCl or CaCO3. Many times, after drilling the well, it takes a long time to make its completion. This leads to a questioning about the real conditions of the invaded area by the DIF filtrate: what happens when it takes a long time from the end of drilling and the beginning of the open-hole completion operation? To answer such question, the Petrobras' Research Center (CENPES) performed a CT scan measurement in Berea sandstone samples damaged by a water-based polymeric fluid. The damage was created by one-year exposition of the samples to the DIF used. This work presents and discusses the main results obtained by the experiments. Fluids and core A water-based polymeric formulation, often used by Petrobras E and P during horizontal drilling in Campos Basin, was used in the aging experiments. Tables 1 and 2 show the formulation of the fluid and its properties. Two Berea sandstone samples were used in the tests (Table 3). The samples were initially saturated with synthetic water (30,000 ppm NaCl brine). After that, the samples were saturated by oil, to simulate reservoir conditions (Table 4).

To design, modify, and expand surface facilities is a multidisciplinary task which involves substantial financial resources. It can take months or years to be completed, depending on the size and level of detail of the project. Nowadays, the use of Next Generation Reservoir Simulators (NGRS) is the most sophisticated and reliable way of obtaining field performance evaluation since they can couple surface and subsurface equations, thus eliminating the need to generate lengthy multiphase flow tables. Furthermore, coupling a NGRS with an optimizer is the best way to accomplish a large number of simulation runs on the search for optimized solutions when facilities are being modified and/or expanded. The suggested workflow is applied to a synthetic field which reproduces typical Brazilian offshore deepwater scenarios. Hundreds of coupled simulation runs were performed and the results show that it is possible to find optimal diameters for the production lines as well as the ideal platform location. Foreword Because of an ever growing demand for oil in the world market, the high prices for the barrel of crude, and the growing Brazilian domestic demand for gas, there is a need to quickly develop oil and natural gas fields. Therefore, development decisions, which usually involve high risk and a large amount of resource investments, often need to be taken very early and in a swift manner. In such a scenario, the optimization of the decision-making process can become quite a challenging task; especially if the impact of the uncertainty variables on the workflow and on the project goals needs to be assessed. Flow assurance in the presence of asphaltens, parafins, and low WAT (Wax Appearance Temperature) as well as hydrates, inorganic scale, CO2, H2S, and so forth, brings even more complexity to the problem. The process of calculating, modifying, and expanding surface facilities while accounting for all these variables and their impact on reservoir fluid flow is a multidisciplinary task that involves substantial resources and can take several months or even years to be performed. Optimized pipeline network and surface facilities are those which maximize oil recovery while minimizing CAPEX and OPEX. This task requires a reliable, integrated model such that production / injection prediction is possible and the overall economics of the project can be adequately assessed. Currently, the use of numerical reservoir simulators with optimization tools is the most sophisticated and reliable way to obtain the required quality of the results. Optimization tools allow several development scenarios to be sequentially or simultaneously evaluated. Techniques such as parallel simulation, experimental design, genetic algorithms, Monte Carlo simulations, artificial intelligence systems and global optimizers have contributed to characterize uncertainties and optimize drainage strategies, allowing the quantification of the benefits in order to choose the best scenario [1–8]. Optimization methodologies can be used to verify the potential integration of uncertainty and decision variables, considering all project constraints and preset goals. Among the applications for this type of study, the most important are:sensitivity analysis,the analysis of the impact of uncertainties and risks [3, 7],well location and number of wells optimization [1, 5],optimization and distribution of injection rates,production history matching [4], andproduction strategy optimization [3].

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