Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and the mass of scale that will deposit by the time the system reaches equilibrium -provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in performing these calculations, engineers and chemists often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads to a significant overestimate of the scaling risk.The work presented in this paper addresses this issue by studying data from various fields to identify what can be learnt from the produced brine compositions. A new technique to estimate the range of scaling tendencies that takes account of reservoir precipitation is developed, and the results are displayed in a 3D response surface. This is illustrated for barium sulphate scaling tendency, accounting for different levels of ion stripping.In order to calibrate some simulation parameters, and to identify the more important equations that should be inserted in the reservoir simulation, studies were performed based on the observed data. Different reservoir simulations were used and compared, with a focus on scale management to identify positive and negative aspects of each one.This work has identified that in fields with reservoir temperatures above 120°C and calcium concentrations above 7000 mg/l, significant sulphate stripping occurs due to anhydrite precipitation. This effect is increased where ion exchange leads to a reduction in magnesium and an increase in calcium concentration as the injected brine is displaced through the reservoir.

fax 01-972-952-9435. AbstractAfter producing 400 million barrels of oil along the last five years, Marlim Sul field, situated in Campos Basin, Brazil, applied its first time-lapse seismic acquisition. The oil is being produced from six different reservoirs, each one with different characteristics. The main common point of them is the water drive mechanisms, and therefore the flow path of the injection water is the prime purpose of this 4D action. Almost all producers have seen the breakthrough of water, sometimes after the forecasted time, sometimes before. The seismic data were acquired by a streamer steering system and received special attention in terms of velocity analysis and crossequalization process. The preliminary analysis indicates some interesting conclusions. The water path seems to be less regular than expected from flow simulation and indicates a trend in rock permeability. This knowledge allows a better match of the model, and a better control of production and injection rates. In addition, some areas are less flooded than expected, wich permits the proposal of new infill drillings, in order to recover this additional oil, depending on the economic analysis, as well as a new infill well, proposed before the acquisition, is not in the better position, and may be relocated or cancelled. Furthermore, the communication of two blocks, situated one above the other, was strongly suggested by the presence of an anomaly related to increase of gas saturation in the higher block derived from the depletion of the lower one. These simple conclusions reveal the power of time-lapse seismic acquisition, and evidence the importance of a permanent reservoir monitoring for the optimization of recovery factor and the profitability of the exploitation project.

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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