This paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention. Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others. Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells. Introduction Sulphate scale deposition is a common problem in reservoirs where injected seawater mixes with aquifer brines1,2. For reasons that will be explained in the next section, the problem is most severe in and around the production well bores, and can cause considerable disruption to hydrocarbon production after water breakthrough. To deal with the problem two general tasks must be performed. Firstly, the quantity and type of scale must be identified, together with the location and timing of the deposition. Secondly, a suitable removal and/or prevention strategy must be designed and implemented. Both of these tasks require reservoir and laboratory data, and field experience is also a vital component in ensuring successful treatment. Both tasks are routinely assisted by application of appropriate modelling tools3. The use of reservoir simulators to predict the timing and location of water breakthrough, and the application of scale prediction codes to identify the scaling regimes, have both been discussed previously4–9. In addition, models are routinely used in chemical scale inhibitor selection studies and to optimize inhibitor squeeze treatments10. The topic of this paper is not so much the design of scale prevention treatments, although the findings have a bearing on this, but on identifying scale deposition regimes throughout an actual reservoir system. To do this produced brine chemistry data and field fluid flow modelling have been analysed on a well-by-well and field-wide basis for the Alba Field in the North Sea. The evidence of both the produced brine chemistries and the flow calculations is that scale is depositing deep within the reservoir. However, the extent and impact of this deposition varies throughout the reservoir. Three regimes are identified, where the nature of the scaling problem at individual production wells can be related to the flow characteristics in that locality. Important factors are shown to be the proximity of injection wells and the proximity and extent of the aquifer.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention.Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others.Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells.

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

A system engineering approach can enhance the prospects of field developments by removing the demarcation between technical disciplines. Considering the system as a whole from the reservoir through to final export over the field life can realise significant benefits and this paper will demonstrate how this approach has been successfully applied to one project in detail. The traditional approach to fields is for a reservoir team to analyse the reservoir development scheme and develop production profiles. These profiles then form the basis of the facilities design. The facilities design is then carried out on this fixed basis of design. Economics are then applied using the capital cost from the facilities design and the production profiles from the reservoir analysis. This approach can take considerable time and can have little interface communication. An alternate approach is to condense the reservoir knowledge into a model that can be integrated into an overall system model which can then be run over the life of field. The model is intended to be simple and fit for purpose and as such, the ease of calculation allows many more outcomes to be considered. These models can be developed further to include the full economic analysis as well. As the models are simple and computationally efficient, risk analysis can be applied to them such that all the key uncertainties can be analysed and risk profiles developed. This can be used to develop the facilities in such a way as to reduce the development risks. This approach is quick and efficient with the end result being a much more robust system design. Introduction There is widespread recognition of the need for integrated approaches to field development planning. The usual methods of integration can be divided into three groups ––manual links between detailed, discipline-specific models (such as economics, detailed facilities andreservoir simulator models)–integrated models containing summary descriptions (e.g. material balance models or look-up tables) of the reservoir behaviour–integrated models containing the full reservoir simulation models of the subsurface. Models in the latter two categories are often called "system models." Manual methods are the traditional approach. The reservoir team develops production profiles. These profiles form the basis of the facilities design. Economics are then carried out using the capital cost from the facilities design and the production profiles from the reservoir analysis. This approach can take considerable time and can have little interface communication. Examples of integrated models with summary descriptions of the reservoir can be found in Huseby and Braekken [1] and in various methods of linking PIPESIM-FPT models with economic models. For reasons that will become clear, these models often run into the difficulty that the summary reservoir models behave well only within certain, very narrow bands.