In Campos Basin, deepwater offshore Brazil, permanent downhole gauges are used to record pressure and temperature. Pressure data are used extensively in well analysis, but temperature data have seen little use. Production data indicate that downhole temperature changes as a function of flowrate, pressure and fraction of fluids. A strong relationship was observed between flowing temperature and gas-oil ratio (GOR), caused by cooling upon expansion. It has also been observed that temperature data can be used to detect scale occurrence, aiding reservoir management. This paper proposes a methodology based on a semi-empirical equation that makes use of downhole temperature data to estimate GOR. The energy balance applied to the wellbore was simplified to generate an equation suitable to use with easily obtainable field data. The resulting equation has two unknown parameters, which are obtained by adjusting the model to field data. The inputs used to calibrate the model are GOR, oil flowrate, watercut and downhole temperature. The use of this methodology to three horizontal wells will be presented. For well C, the mean error obtained while estimating the GOR measured at the tests was 6.6%. In well B, the mean error was 11%. Well A has passed through a wide range of liquid flowrates, and over the 150 production tests that were performed before water breakthrough, the model was able to estimate the GOR with a mean error of 5.4%. However, after water breakthrough it could not reproduce the measured data accurately. In Campos Basin, accurate GOR measures are difficult to obtain, particularly after gas-lift start-up, because gas flowrate measurement is unreliable and test separators are often unavailable. Using this methodology, it is possible to obtain estimates of the GOR, which is desirable for an improved definition of the waterflood strategy and as a refined input for material balance in specific regions of the reservoir.
Scale occurrence in a giant oilfield located in deepwaters off the Brazilian coast required the implementation of strategies to remediate and prevent scale formation, which was a cause of significant production loss in the field. To prevent scale formation, inhibitor squeeze treatments have been utilized since 2006, when two squeeze treatments indicated an inhibitor lifetime lower than the predicted from laboratory tests. The inhibitor used is derived from the phosphonic acid, making it possible to analyze the inhibitor concentration in the produced water, and consequently, determine its lifetime. Despite the lower lifetime, the wells did not show any production loss, even when inhibitor concentrations were lower than the minimum inhibitor concentration (MIC), determined in laboratory tests. Throughout 2007, due to operational and contractual concerns, it was not possible to perform the squeeze treatments. Consequently, by the end of that year, production losses were verified. In 2008, the inhibition campaign was restarted, and based on the results of 2006 operations, the squeeze treatment volumes were recalculated, in order to obtain a higher inhibitor lifetime. As a result, it was possible to extend the treatment lifetime and maintain the production of the wells stabilized. Historic cases of three wells will be shown, emphasizing the extensive production loss verified when the treatment was not performed, the impact observed in the production when the treatment was delayed and the success obtained when the treatment schedule was accomplished. Beyond the scale occurrence in the production wells, there are also severe scale problems in the production facilities, which will be discussed in this paper. This work describes and details the scale monitoring, prevention and remediation strategies employed in this field, exposing the results obtained, as well as the learned lessons and opportunities to improve the scale management strategy.
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