Injection of chemicals into a subsea multiphase production system is a crucial measure to mitigate flow assurance concerns such as hydrate formation, wax deposition, scale and corrosion aspects. The chemical injection process is therefore applied for different purposes and the effectiveness depends upon operating conditions and inhibitor product chemistry; which is supplied by the vendor and accuracy of this data is a key. However, if these chemicals are applied within extreme conditions, such as fluctuating high temperature and pressure then the properties of the inhibitor will change or create the occurrence of incompatible reactions. These scenarios could lead to blockage of the production core or result in additional erosion and corrosion concerns. Some oil and gas operators share their experiences to aid in our understanding of the problem; however relevant procedures and standards are absent for industry to follow, in particular for downhole chemical injection.
The delivery mechanism between onshore and offshore injection systems are quite different and accurate replication of inhibitor performance in a laboratory is not always able to simulate the realistic subsea conditions; therefore resulting in potentially nonconservative estimation when that data is applied for downhole simulations. Transferring of laboratory data to the subsea system can result in some discrepancies, hence the occurrence of unexpected problems. It is proposed within this paper to present a holistic or system engineering approach to inhibitor performance within a subsea system, suggesting how to determine the chemical injection flowrate based on onshore laboratory data but taking account of the subsea production conditions through the consideration of the potential variations in the production fluid properties and whether the installation of a monitoring device, such as a CIMV (Chemical Injection Metering Valve) is beneficial or not to the performance of the full subsea system. In addition, the injection of scale inhibitor at the downhole location can result in debris blockage and resultant pitting corrosion if an unexpected incompatible reaction occurs, i.e. Statoil experience (SPE 154967, 2012).
This study aims at performing quantitative risk assessment of system / lifecycle analysis to understand the limitations and constraints of each part of the system, i.e. the fluid, the chemical reaction, and the hardware, thereby to reconcile to the operating conditions by taking into account different multiphase flow behaviour and production scenarios, due to the discrepancy between laboratory test results and practical operation. The potential risk of injection failure (i.e. debris formation at scale inhibitor injection valve) and pitting corrosion attack (i.e. hydrostatic pressure fluctuations due to injected chemicals to be evaporated) will be quantified. In addition, the possible concentration increase of the injected inhibitor (emulsion problem) and the compatibility of the fluid will also be evaluated and briefly discussed in this paper. These quantitative risk analysis results can aide in building a system picture that may allow the future mitigation of potential hazards in downhole continuous chemical injections.