Trace amounts of metal chelant additives, commonly used in stimulation and fracture fluids, have been shown to have a debilitating effect upon the performance of widely used barium sulfate scale inhibitors. EDTA and citric and gluconic acids render examples of some commonly u s e d scale inhibitors (phosphonates, polycarboxylates and phosphate esters) completely ineffective at concentrations as low as 0.1 mglL. Such low concentrations may be expected to return from formation stimulation treatments for many months and would appear to jeopardize any scale inhibitor program in place. The testing was based upon a simulated North Sea scaling system at pH 4.0 and 6.0. Scale inhibitor concentrations studied were 50 and 1 00 mglL The large negative effect of the organic chelants was observed at pH 4.0 and 6.0. The only scale inhibitors studied which remained ambivalent to these interferences were large polymeric vinylsulfonates.
Thle paper wee aelactedfor presentationby the OTC PrcgramCommitteefollowing ravlewof informationmntalned In an abetrac4aubmittadby the author(e).Contentsof the paper, aa praeentad,have not bean reviewedby the OffshoreTaehnologyConferenceand are subjaetto correctionby the eulhor(s).The material,an presented,done not necessarilyreflect Y Wai~On~the OffshoreTechnologyConferencew 11s offhva. Permlaaionto WPYla raatrlctedto an abetrecfof net morethan 300words.Illuetretlonemaynot be cepled.me abetract should oentaln ccmaplcuoue acknowledgmentef tiere and by whom the paper ISpraeented. ABSTRACTSevere scaling conditions exist in South Brae due to the high barium content of formation water and low pH downhole.Formation water is also susceptible to calium carbonate scaling.This paper presents experiences with control of scale on topsides and downhole during development of the field.A sulphonate-based inhibitor has been developed and app1ied for downhole control of BaS04.The benefits achieved by the use of d.ssulphatedseawater to minimise the BaS04 potential are presented. The methods developed for controlling calcium carbonate scale are described.
Summary Severe scaling conditions exist in South Brae because of the high barium content of formation water and low pH downhole. Formation water is also susceptible to calcium carbonate scaling. This paper presents experiences with scale control on topsides and downhole during field development. Topsides control has been achieved at the expense of high dose rates and secondary effects on produced-water quality. A sulfonate-based inhibitor was developed and applied for downhole control of BaSO4. This paper presents the benefits achieved by the use of desulfated seawater to minimize the BaSO4 potential and describes the methods developed to control calcium carbonate scale. Introduction Deposition of mineral scale is a common problem in the oil industry, nowhere more so than in the North Sea.1–5 The type of scaling and its severity vary among fields; however, calcium carbonate and barium sulfate scaling are common problems. The barium content of most North Sea formation waters ranges from 10 to 200 ppm. By comparison, the barium concentration in South Brae formation water is as high as 2,500 ppm. This high barium content in injection seawater presents a severe scale mitigation problem that is compounded by a relatively low downhole pH. Although similar high barium levels have been found in other North Sea fields (e.g., T Block),6 South Brae is the first such North Sea field to be developed. This paper presents an overview of the experience gained with the scale problem and the control measures developed. The South Brae field is located in Block 16/7a of the U.K. sector of the North Sea. Phillips7 recently described the reservoir and its geology. The field has been on production since 1983. Reservoir pressure maintenance and voidage have been achieved by a combination of downdip water injection and crestal-gas injection. Seawater injection began in 1984. In 1988, the first phase of a 120,000-bbl-capacity facility to reduce sulfate levels of injected seawater was installed. Scaling Predictions Formation-Water Composition. Assessment of the scale potential was initially uncertain owing to the large variation in the compositions evident in the limited number of formation-water samples. Samples obtained subsequently have confirmed the heterogeneity in water compositions. Table 1 gives examples. Salinity and barium content increase with depth, the barium concentration varying from approximately 500 to 2,500 mg/L. Barium Sulfate Scale Potential. The theoretical mass of scale formed upon mixing formation water with seawater and the mixing ratio at which it occurs vary, depending on the barium content. However, for a typical formation water containing 800 ppm barium, the highest mass of BaSO4 is formed at a 80:20 formation/seawater mixing ratio. The highest saturation index (i.e., driving force for scaling) occurs at a mixing ratio of approximately 50/50. These predictions agree closely with Mazzolini et al.'s6 for similar high-barium-content T Block water. It was apparent that, because of the high supersaturation, barium sulfate scale would be difficult to inhibit. The high CO2 content of the produced gas (30 to 32 mol%) and consequent low pH further contribute to the difficulty of inhibition. Downhole pH is estimated to be between pH 4 and 4.5, at which point the efficiency of many conventional inhibitors is limited. Calcium Carbonate Scale Potential. In addition to severe barium sulfate scaling, because of the significant calcium and bicarbonate content, South Brae formation water is prone to calcium carbonate scaling. Oddo and Tomson's8 method was used to calculate the downhole CaCO3 scaling tendency.
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