Cementing through coiled tubing is not a new service line. However, it remains one that has received little technical attention. In reality, there is a great deal of science behind the successful execution of such cementing operations. Failure to understand the complexities of cement placement in a well can lead to catastrophic failure, including the loss of the coiled tubing, the entire well, or both.
This paper outlines the techniques behind cementing through coiled tubing, illustrating the pitfalls and suggesting best operating procedures. The issues covered are: -
When to use cement darts.
How to land cement darts.
How to manage liquid freefall.
How to clean up cement.
What should the displacement/contaminant fluid be?
What are the best nozzles?
Cementing is an every day operation in the oil patch, the most common application being the cementing of steel casings and liners in the ground. Cementing through coiled tubing is a much smaller business but nevertheless is conducted daily throughout the world.
The typical cementing application through coiled tubing is not one of placing large volumes of cement behind casing strings; it is one of placing a relatively small volume of cement in a well for remedial purposes. Typical applications are: -
Curing channeling behind tubulars.
Blocking off perforations.
Squeezing off perforations.
Placing, in conjunction with packers, for wellbore isolation or abandonment.
Placing through holes in completion strings to produce "cement packers".
Curing lost circulation zones during drilling.
Forming plugs for drilling sidetracks - "cement whipstocks".
In all of these applications, the initial goal is to place a volume of uncontaminated cement at some point in a well. Subsequently, the cement may be squeezed against the formation, left to set in place, or circulated out before it sets. Each of these operations has potential pitfalls that can lead to quite catastrophic failures. This paper lists some of these potential failures and illustrates the correct procedures designed to minimize the risk of such failures. The paper refers only to pumping small volumes of cement through coiled tubing, not to primary cementing operations through large tubulars. Unique aspects of coiled tubing work lead to differing procedures for the two different applications.
The chemistry of cement is complex and is not the subject of this paper. This paper refers only to the physical properties of the cement slurry during placement.
Oilfield cement is typically "Class G" or "Class H" cement particles suspended in water along with other solid and liquid additives. It is principally calcium silicate with particle sizes ranging from 1µm to 100µm, averaging 20µm. When mixed with water, the cement slurry sets with time to form a largely impermeable (1µD), largely acid resistant, solid material that is strong in compression, weak in tension.
Cement slurries are typically dense as compared to water, although they can be mixed with a wide range of densities through the use of different additives. The standard density of "Class G" cement is 15.8ppg, or a specific gravity of 1.9.
Cement slurries are very abrasive and can quickly destroy bottom hole assemblies that generate high fluid velocities and are not made of wear resistant materials such as tungsten carbide.