This paper presents recent case studies where down-hole pressure and temperature sensors, run on coiled tubing, provided real-time measurement of matrix acid treatments in the Gulf of Mexico. The information obtained during these jobs allowed on-site design and execution changes to the treatment. Four case studies are presented to demonstrate how the sensor information was used to optimize the treatment of each well.
Coiled tubing is often the preferred acid placement method for a variety of reasons.
The coil provides a clean dedicated work string reducing the risk of acid contamination with materials such as rust, pipe dope and scale often found in production tubing.
Tubing components, such as, gas lift mandrels, acid sensitive metals, unusual downhole layout, or simply large displacement volumes may prompt the use of coiled tubing.
Poor formation injectivity may prevent bullheading of fluids into the formation.
Sand across the perforations may require a pre-treatment clean out.
Completion type, such as horizontal wells or commingled completions, may require coiled tubing to place the acid where it is most needed.
After pumping an acid treatment, some formations do not have sufficient pressure to lift the spent acid. Coiled tubing allows nitrogen to be circulated reducing the hydrostatic pressure allowing the well to flow.
When coiled tubing is selected as the workstring for an acid treatment, monitoring the bottom hole injection pressure is conventionally done either of two ways. One way is to use circulating pressure add hydrostatic pressure and subtract friction pressure, another way is to monitor the annular pressure between coil and production string and add hydrostatic pressure. The disadvantage with these methods is that the following assumptions have to be made in order to calculate an accurate bottom hole pressure (BHP).
A single phase slightly compressible fluid of near constant density.
A full column of fluid.
Known friction pressures.