New Test Methods Examine Why Downhole Chemical Injection Lines Fail
- Adam Wilson (JPT Editorial Manager)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2013
- Document Type
- Journal Paper
- 119 - 121
- 2013. Society of Petroleum Engineers
- 6 in the last 30 days
- 204 since 2007
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This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154967, "Downhole Chemical Injection Lines: Why Do They Fail?—Experiences, Challenges, and Application of New Test Methods," by Britt Marie Hustad, Odd Geir Svela, SPE, John Helge Olsen, SPE, Kari Ramstad, SPE, and Tore Tjomsland, SPE, Statoil, prepared for the 2012 SPE International Conference and Exhibition on Oilfield Scale, Aberdeen, 30-31 May. The paper has not been peer reviewed.
Downhole continuous injection of chemicals 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. Designing, operating, and maintaining the chemical injection lines demand 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. Over the years, several challenges concerning downhole chemical injection lines have been experienced. Two case histories are given, one on corrosion and one on chemical gunking.
Downhole Chemical Injection Systems
Cost Benefit. Continuous injection of SI downhole to protect the DHSV or the production tubing may be cost effective compared with squeezing the well with SI. This application reduces the potential for formation damage compared with scale squeeze treatments, reduces the potential for process problems after scale squeezes, and gives a possibility to control the chemical injection rate from the topside injection system.
Continuous Injection System and Valves. Typically, the injection system (Fig. 1) consists of a capillary line with a ¼- or ⅜-in. outside diameter hooked up to a surface manifold and fed through and connected to the tubing hanger on the annular side of the tubing. The capillary line is attached to the outer diameter of the production tubing by special tubing collar clamps and runs on the outside of the tubing all the way down to the chemical injection mandrel. The mandrel is traditionally placed upstream of the DHSV or deeper in the well to give the injected chemical sufficient dispersion time and to place the chemical where the challenges are found.
At the chemical injection valve, a small cartridge approximately 1.5 in. in diameter contains the check valves that prevent wellbore fluids from entering the capillary line. It is simply a small poppet riding on a spring. The spring force sets and predicts the pressure required to open the poppet off the sealing seat. When the chemical starts flowing, the poppet is lifted off its seat and opens the check valve.
Two check valves are required. One valve is the primary barrier preventing the wellbore fluids from entering the capillary line. This has a relatively low opening pressure (2–15 bar). If the hydrostatic pressure inside the capillary line is less than the wellbore pressure, the wellbore fluids will try to enter into the capillary line. The other check valve has a typical opening pressure of 130–250 bar and is known as the U-tube prevention system. This valve prevents the chemical inside the capillary line from flowing freely into the wellbore should the hydrostatic pressure inside the capillary line be greater than the wellbore pressure at the chemical injection point inside the production tubing.
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