This paper discusses carbonate and sulfate formation in the Forties field and some of the laboratory inhibitor-selection techniques used to evaluate scale inhibitors for field use in the Forties injection and production systems. Two chemical treatments for stimulation injection wells also are described.
Pressure maintenance in the Forties field began in Dec. 1976. Initial water sampling and core injectivity studies indicated that seawater would be a satisfactory injection fluid.Before commencing injection, the chemical treatment requirements for the seawater injection system were determined. The principal requirement at that time was for an effective microbiological treatment. This was discussed in detail in an earlier publication. Since that time the need has arisen for injection of suitable scale inhibitors into both the injection and production systems to prevent calcium carbonate and barium sulfate scale formation. This paper discusses scale formation in the Forties field and some of the scale-inhibitor selection techniques used. In particular, a novel test method is described that is used to monitor inhibition and flow pattern influence on formation scaling.The water quality aspects of North Sea injection water have been discussed in detail previously. In that study numerous core injectivity measurements were carried out, and the major core plugging mechanism was attributed to the organic portion of seawater. Although no similar plugging has been detected downhole, BP Research has developed a suitable well treatment product to remove organic debris. Some of the results of this study are discussed in relation to potential field application.
Scale problems occurring in the Forties field can be attributed to two major factors:
commingling of Forties formation and injection waters and
precipitation of calcium carbonate scale from formation water due to variations in pressure and temperature in production systems.
A partial chemical analysis of Forties formation water and North Sea injection water is given in Table 1. It will be seen that the commingling of formation water and seawater can precipitate both barium and strontium sulfates, which probably are the worst types of scale found in oilfield situations. The solubility of barium sulfate has been calculated as a function of temperature and mixing composition. The results are shown in Fig. 1 and are presented as a stability index, which is the logarithm of the ratio of actual barium sulfate present to the barium solubility under the specified conditions. For example, a stability index of +0.3 indicates the actual barium sulfate present exceeds the solubility limit by a factor of 2 (10 (0.3)).The worst condition exists for relatively large amounts of formation water and small amounts of injection water.