Method development of laboratory bench and rig tests for assessing the suitability for application of chemicals via down-hole pressure tube systems is presented. Areas of interest include precipitation or viscosity changes due to solvent loss both in bulk samples and samples in capillaries, and long term product stability in capillaries using new flow rigs designed to more fully replicate pressure tube injection phenomena (particularly chemical stability under extreme T and P conditions). Indeed fluid stability and other challenges relating to down-hole continuous injection have led to a number of failures being recorded in recent years indicating that the physical properties rather than the absolute performance of the chemicals is often key to their successful deployment.Continuous chemical injection systems for down-hole application are being included in more well completions as their usefulness is recognised. While the initial capital costs are increased, such systems provide a number of benefits over reliance on squeeze treatments for down-hole application. These may include the opportunity to use chemicals unsuitable for squeeze treatment due to the risk of formation damage, the ability to maintain higher doses, and avoiding the need to interrupt production to apply chemicals in complex subsea wells.Using the developed methods we have identified a number of ways in which formulated scale inhibitors may produce problems within continual injection systems. These include particulate formation and line plugging in capillaries, and solid formation or viscosity increases in response to solvent loss within a tube (as opposed to bulk samples).These methods will form the basis for future qualification procedures for chemicals intended for down-hole chemical injection with the aim of avoiding application issues in the field. They have been developed both to better understand chemical / fluid stability under down-hole continuous injection conditions following a number of recorded field deployment problems, and then to provide improved qualification for new chemicals and systems.

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Statoil is operating several fields where downhole continuous injection of scale inhibitor is applied. The objective is to protect the upper tubing and safety valve from (Ba/Sr)SO 4 or CaCO 3 scale, in cases where scale squeezing may be difficult and costly to perform on a regular basis, e.g. tie-in of subsea fields. Continuous injection of scale inhibitor downhole is a technically appropriate solution to protect the upper tubing and safety valve in wells that have scaling potential above the production packer; especially in wells that do not need to be squeezed on a regular basis due to scaling potential in the near wellbore area. Designing, operating and maintaining the chemical injection lines demand extra focus on material selection, chemical qualification and monitoring. Pressure, temperature, flow-regimes and geometry of the system may introduce challenges to safe operation. Challenges have been identified in several kilometers' long injection lines from the production facility to the subsea template and in the injection valves down in the wells. Field experiences showing the complexity of downhole continuous injection systems regarding precipitation and corrosion issues are discussed. Laboratory studies and application of new methods for chemical qualification are presented. The needs for multidisciplinary actions are addressed.

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Downhole Continuous Chemical Injection (DCI) systems, including both Downhole Continuous Injection systems (DHCI) and Gas Lift Chemical injection (GLI) are increasingly being installed in new wells for the application of a range of chemicals. These systems have one or more check valves at the point of injection to control the chemical flow into the wellbore and prevent wellbore fluids from entering the injection lines. In-line filters are included to remove particulates that may prevent the check valves from sealing. The performance of the injection valves is key to the success of continual injection systems. Valve failure would lead to uncontrolled injection into the wellbore, forming low pressure gas pockets within the injection lines which can lead to changes in the physical properties of the chemical causing issues such as corrosion or gunking. In addition, if the hydrostatic pressure within the injection line drops below wellbore pressure, then wellbore fluids can start to enter the capillary tubing. Currently, the qualification of valves is conducted using either fresh water or nitrogen. In conjunction with considerable developments made in qualification of chemicals for DHCI and GLI which were introduced in previous papers1, 2, work has been undertaken to improve the qualification of the injection system itself. This means that in addition to showing compatibility and good performance, the chemical must be suitable for the application system, and the equipment suitable for the chemical selected. Results demonstrate how different valve/chemical combinations can perform well during fluid injection but fail to hold pressure within the injection line when the flow is stopped. The paper will present results from an extensive series of valve tests conducted in a newly designed and commissioned rig capable of operating at full reservoir temperatures (up to 200 °C) and elevated line pressures (up to 5,000 psi). The results from this work are expected to form the basis of a new range of system qualification protocols to be proposed for Statoil DHCI systems.