In North Sea oil and gas fields, seawater injection is used for reservoir pressure support. Formation water and seawater mixing may lead to sulphate scaling in the near wellbore area, tubing and process systems. Scale inhibitor squeeze treatments are applied to protect the producers and extend the field lifetime. Reducing cost and prolonging the squeeze lifetime is essential. In some StatoilHydro operated fields, squeeze lifetime has been evaluated based on inhibitor return concentration and cumulative water treated. Field experience and laboratory studies have determined the criteria for re-squeezing the wells.
One critical aspect of downhole scale management is the laboratory determined Minimum Inhibitor Concentration (MIC) of the squeeze inhibitor. If the MIC is lower than the concentration of inhibitor required to prevent scale at real conditions the well could scale up. Field examples are given where sulphate scale was observed downhole and in the tubing around the safety valve even if the inhibitor concentration was above the laboratory determined MIC. MIC varies throughout the well lifetime according to variation in brine chemistry/operating conditions and should be re-evaluated frequently.
Polymer squeeze inhibitors are difficult to measure with sufficient accuracy at low concentration. However, adequate preservation of the water samples may improve the detection. The volume of water produced before reaching MIC can be significantly increased with improved inhibitor detection methods.
Laboratory studies have been performed addressing the sensitivity of inhibitor detection as function of ion composition, inhibitor concentration, particles and preservation additive. Parallel samples have been taken offshore. MIC has been determined for a range of formation/seawater mixtures.
The paper describes laboratory analyses, sampling procedures, well monitoring, inhibitor return detection and field/well lifetime MIC determination as methods to determine a long but safe squeeze lifetime.
In North Sea oil and gas fields, seawater injection is frequently used for reservoir pressure support. Mixing of formation water (FW) and injected seawater (SW) may cause sulphate scale to form in the production system (Cowan & Weintritt 1976). Scale in the near wellbore area may give severe formation damage and reduce well productivity. Scale in the production tubing may compromise well integrity by causing safety valves to fail, while scale in the topside process may lead to insufficient separation and poor water quality. If not handled properly, all these mechanisms may give significant production losses. It is necessary to continuously update scale management strategies for the protection and maintenance of the system in order to extend the field lifetime.
Scale inhibitor squeeze treatments are applied regularly to protect the near wellbore area and the tubing of the wells. Additional topside scale inhibitor is continuously injected at the wellhead of each well and at dedicated locations in the process facility. The efficiency of the squeeze treatments is monitored through water sampling focusing on e.g. inhibitor and ion concentrations and amount of suspended solids in the samples. The Productivity Index (PI) (Sm3/d/bar) is also an important indicator of the well protection against scaling. To fully exploit the well asset potential it is important to maintain the PI as high as possible throughout the lifetime of the well. If there is enhanced risk of scale it may be necessary to increase the frequency of downhole safety valve (DHSV) testing and/or perform slam tests to remove any scale buildup (Ramstad et al. 2005).