Tore Tjomsland

Downhole Chemical Injection Lines - Why Do They Fail? Experiences, Challenges and Application of New Test Methods

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)SO4 or CaCO3 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. Introduction Statoil is operating several fields where downhole continuous injection of chemicals has been applied. This mainly involves injection of scale inhibitor (SI) where the objective is to protect the upper tubing and downhole safety valve (DHSV) from (Ba/Sr)SO4 or CaCO3 scale. In some cases emulsion breaker is injected downhole to start the separation process as deep in the well as possible at a relative high temperature. Continuous injection of scale inhibitor downhole is a technically appropriate solution to protect the upper part of the wells that have scaling potential above the production packer. Continuous injection might be recommended especially in wells that do not need to be squeezed because of low scaling potential in the near wellbore, or in cases where scale squeezing may be difficult and costly to perform on a regular basis, e.g. tie-in of subsea fields. Statoil has extended experience on continuous chemical injection to topside systems and subsea templates but the new challenge is to take the injection point further deep into the well. Designing, operating and maintaining the chemical injection lines demands extra focus on several topics; such as material selection, chemical qualification and monitoring. Pressure, temperature, flow-regimes and geometry of the system may introduce challenges to safe operation. Challenges in long (several kilometers) injection lines from the production facility to the subsea template and into the injection valves down in the wells have been identified; Fig. 1. Some of the injection systems have worked according to plan, while others have failed for various reasons. Several new field developments are planned for downhole chemical injection (DHCI); however, in some cases the equipment has not been fully qualified yet. Application of DHCI is a complex task. It involves the completion and well designs, well chemistry, topside system and the chemical dosage system of the topside process. The chemical will be pumped from topside via the chemical injection line to the completion equipment and down into the well. Hence, in the planning and execution of this type of project cooperation between several disciplines is crucial. Various considerations have to be evaluated and good communication during the design is important. Process engineers, subsea engineers and completion engineers are involved, dealing with the topics of well chemistry, material selection, flow assurance and production chemical management. The challenges can be chemical gunking