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The Veslefrikk field, located in block 30/3 of the Norwegian sector of the North Sea, has been on production since 1989 and is in the decline phase. Due to seawater injection, commingled production and high reservoir temperature, severe tendency towards deposition of sulphate and carbonate scale has been observed. The economic consequences of scale and the benefit from scale control work had been assessed quantitatively and presented at the 2001 SPE Third International Symposium on Oilfield Scale (Tjomsland et al., 2001). The study showed that the scale control strategy had been an economic success. However, annually more than 4% of the well productivity was still lost due to scale deposition, and in consequence it was recommended to intensify the scale management procedures. A task force involving scale control experts from the licence partners was established. In co-operation with service companies, the group systematically assessed new scale control measures for use at Veslefrikk. In 2006 a benchmark against the 2001 study was performed to investigate if the scale control work had been improved. The results showed that the scale potential was approximately the same in the second period (June 1999–2005) as in the first (1993- May 1999), but a significant improvement in downhole scale control was now obtained through a more aggressive use of preventive scale inhibitor squeezes and the implementation of new technology. However, the study also concluded that scale inhibitor squeezes themselves in some cases caused formation damage, most likely due to the formation of water blocks. Recently a mutual solvent that can be incorporated as part of the squeeze pre-flush was qualified for use on Veslefrikk. This has not only reduced the risk of formation damage, but in some cases even increased productivity has been observed. Introduction The Veslefrikk field is located in block 30/3 of the Norwegian sector of the North Sea. The field has been on production since 1989. It was developed by a 24 slot wellhead platform with drilling facilities in combination with a semi-submersible process platform with a living quarter, Figure 1. The production rate peaked in 1995, and the field is now far into the tail production phase. Seawater injection has been the main method of pressure support, but gas injection has also been performed to increase the recovery factor. The first water breakthrough was observed during 1992. The field water cut has now reached 80–85%, and in average the produced water contains 50–60% seawater. The Veslefrikk reservoir is layered, consisting of several zones with independent pressure regimes and to some degree also different fluid systems. Commingled production is extensively used at the field, due to the limited number of well slots and to optimize the production rate. Scale potential at Veslefrikk The two most common types of scale in the Veslefrikk field are calcium carbonate (CaCO3) and barium sulphate (BaSO4). Calcium carbonate can precipitate if produced fluid containing formation water is pressure depleted, for instance when flowing into or inside the well. The calcium carbonate saturation ratio (SR) increases as the pressure is reduced (see Figure 2), mainly due to the reduced amount of carbon dioxide (CO2) dissolved in the water phase when the pressure is reduced (Tjomsland et al., 2001).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Heidrun Field, located on the Haltenbanken area, is one of the major fields which came on stream in the Norwegian Sea since 1995. At peak production the field is capable of producing 38,000 m 3 of oil and 6 MSCM gas per day. It also takes in 22,000 m 3 of injection water each day. The field is characterised by the large clay content in its three formation sands Fangst, Tilje and Åre. Most of the producing wells are installed with gravel pack or screens due to poor sand consolidation. The reservoir has a bottom hole temperature of 85 o

Some of the wells in a North Sea field have a relatively low reservoir pressure. For those wells without gas lift installed, lifting heavy fluid out of the well when flowing back can be a problem. For this type of well, one of the options for the inhibitor squeeze treatments is to use a low density package to avoid pumping a large amount of relatively heavy brine based inhibitor. Through a research program, a polymer inhibitor and non aqueous solvent based package was developed for the squeeze treatments for the field. This paper will present the detailed discussions of the chemistry of the formulation package. A number of scale inhibitors were screened for the suitability with a low density solvent as a carrying fluid. Due to both environmental concern and different function groups attached on the inhibitors, very limited inhibitor candidates were found to be suitable for being formulated into the low density package. The paper will further present the laboratory evaluation results such as product compatibility, inhibitor partitioning from solvent to brine phase, inhibitor efficiency as well as core flood data. The paper will also present the field evaluation data. One well treated with this low density package squeezed a water based inhibitor with several times in the past. Due to the reservoir pressure depletion, the low density package was developed for the squeeze treatments. The same inhibitor used in the water based squeeze was formulated into the non-aqueous package. The field trial results show that none of the wells experienced lifting problems while back producing the inhibitor pill. In most of the wells, an improved oil production was seen and maintained for a while after the treatments. A possible mechanism for this will be discussed. In addition, a comparison was made between the treatments from the water based and non-aqueous squeezes.

Summary Scale inhibitor squeeze treatments have regularly been conducted to prevent both sulphate and carbonate scale depositions in a specific North Sea field for more than 10 years. However, some wells, in which the fluid is producing from the "clean" sandstone formation, have experienced relatively short squeeze lives, when squeezing a conventional phosphonate scale inhibitor treatment. A research program has been conducted to develop a novel polymer scale inhibitor chemistry, which combines performance in a number of laboratory static and dynamic tests, with improved scale inhibitor adsorption properties on "clean" sandstone formations. Field trials have also been conducted with satisfactory results. This paper outlines the concept of how novel scale inhibitor chemistry was developed by incorporating a special monomer to make the final copolymer scale inhibitor. The monomer was introduced to enhance the inhibitor adsorption properties, because it carries a special functional group to improve the scale inhibitor affinity for the reservoir rock. This special functional group plays a key role for the newly developed scale inhibitor, to give improved and acceptable squeeze lives. A critical aspect of the program included optimizing the monomer content to achieve a good adsorption/desorption balance, to ensure that the scale inhibitor would be desorbed/released from the reservoir rock to meet the requirements of an acceptable squeeze program. An added bonus was that the environmental properties of the scale inhibitor polymer were also improved because of the introduction of the special monomer. A number of beaker and dynamic loop tests were conducted and the inhibitor showed an excellent efficiency in both sulphate and carbonate scale inhibition performance tests under the test conditions adopted. This paper also presents detailed laboratory and field data; the treatment design strategy and deployment method adopted for the scale inhibitor.