Drilling/completion fluids

Packer-Leak Repair: Slurry Design and Complex Coiled-Tubing Well Work

A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure.


A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure. Through-tubing well work was used because it is more economical than a full workover, particularly for wells in a mature field with depleted reserves. Enhanced and optimized cement slurry was engineered with a well-work approach that specified acoustic fluid-level monitoring. The packer leak was repaired successfully.


This oil and gas field is 260 km from Kerteh, Malaysia. Discovered in 1971, first oil production was in 1978. The field is in the southeastern part of the Malay basin at an average water depth of 70 m. The field contains both gas and oil reservoirs.

In August 2002, communication was observed between the production casing and tubing of the subject well, indicating a leaking production packer. Four major attempts to correct the problem were conducted, all unsuccessful. The first attempt was in February 2003 by bullheading calcium carbonate (CaCO3) into the annulus. This procedure was attempted again in May 2003. In August 2007, a coiled-tubing (CT) unit was used to spot cement inside the production tubing and displace it into the annulus through a gas lift mandrel to the top of the packer. Another cementing job was attempted in December 2008, through the same gas lift mandrel.


Lessons learned from the first cementing failure, in 2007, were used to design the attempt in 2008. Even though job execution was smooth in the field, several mistakes occurred that were not realized by the team during the job-design process. The experiences of those cementing attempts helped mature the subsequent design and decisions, ensuring success for future packer-cementing jobs in peninsular Malaysia operations.

Cement-Slurry Design. CT-cementing procedures are different from those of conventional/primary cementing from a rig, with the biggest difference being the need for batch mixing for CT cementing vs. on-the-fly mixing for primary cementing. Batch mixing requires higher mixing energy compared with primary cementing, with an additional mixing energy to pump the cement slurry through the CT relative to pumping down the casing. The higher mixing energy decreases thickening time (TT) such that the cement slurry has potential to accidentally set inside the CT, thereby requiring a suitable retarder to prolong the TT.

On the basis of the two previous CT-cementing attempts, it was determined that the bottomhole-temperature (BHT) specifications of the retarder were incorrect for the well. While the use of high-temperature retarder is permitted for these well conditions, the cement slurry—which needed a longer TT for CT applications—took too long to establish the needed compressive strength (i.e., more than 20 hours for 500-psi compressive strength). Use of the correct retarder for the well’s BHT would develop the required compressive strength within 10 hours.

Use of a high-viscosity gel behind the freshwater tail spacer also affected the cement slurry. With only 2 bbl of tail spacer separating the cement slurry from the gel and the difference in density between the cement slurry, the spacer, and the high-viscosity gel, contamination was likely to occur. It is generally accepted that contamination will occur in the first bbl of fluid interface (in this scenario, cement slurry and tail spacer) and the last bbl of fluid interface (tail spacer and high-viscosity gel). Laboratory studies showed that any contamination between the cement slurry and the high-viscosity gel would prevent the cement from setting properly. This process would not be the direct cause of the previous CT-cementing failures, but it could have contributed in the event of overdisplacement of high-viscosity gel into the casing making the contaminated cement unable to hold the higher-density fluid above it, resulting in a flip-over scenario.

New Method

In 2011, another effort to solve possible leaks at the packer included more details and a contingency plan. The new approach was to use a slurry/mechanical method to secure the leak. On the basis of information gained from the failure analysis, a method was developed to use a cement packer to isolate the casing area temporarily. This method can reduce the potential of losing cement into the casing area and reduces the U-tube effect in the tubing.

Laboratory Test. Cement-slurry design was performed in a laboratory to suit well conditions and to be able to pump through the packer, which had an estimated leak rate of 0.5 bbl/min. From the failure of previous jobs, the effort was to design the cement slurry suitable to well conditions. High-temperature retarder was replaced with different types of retarder during the cement-slurry design. With a new retarder selected, thickening time was reduced to 7 hours, with 1,500‑psi compressive strength achieved in 10 hours. TT was calculated on the basis of total job time including mixing, pumping, and retrieving CT to surface without having the cement slurry hardened in the CT.

Job Steps. Using the approved cement recipe, a CT unit was mobilized and the job was performed as follows.

  • Used slickline to change out the gas lift valve to a dummy valve. 
  • Used slickline to set a plug at the no-go nipple and perform a tubing-integrity test with 1,000 psi and then retrieved the plug.
  • Used an acoustic meter to determine the fluid level in the tubing/casing annulus.
  • Ran CT to perform a casing cleanout at the bridge-plug setting depth.
  • Ran CT with memory gamma ray and casing-collar-locator (GR/CCL) tool in the casing and in the tubing to obtain a base correlation for setting the inflatable bridge plug. 
  • Ran CT to set the inflatable bridge plug. Once set, pulled CT above the inflatable plug to spot the correct amount of CaCO3 to protect the plug profile. 
  • Ran CT to set a cement retainer above the no-go nipple. 
  • Used an acoustic meter to determine the fluid level in the tubing/casing annulus for the initial fluid level before pumping cement slurry. 
  • Ran CT with a cement stinger and stung into the cement retainer.
    • Pumped 5 bbl of seawater to perform the circulation test.
    • Determined the fluid level in the tubing/casing annulus. 
    • Mixed cement slurry and pumped through CT and the cement retainer with a seawater spacer before and after the cement.
  • Cement slurry was pumped through the cement retainer at 0.5 bbl/min into the casing and through the leak point at the packer into the tubing/casing annulus to build a cement packer. 
  • After pumping the cement slurry away, an acoustic meter was used to determine the fluid level in the tubing/casing annulus to ensure the height of fluid in the tubing/casing annulus increased with the addition of cement slurry in the annulus. 
  • After confirming the top of cement in the annulus, the well was shut in to allow the cement to harden.
  • Used CT to mill the cement retainer and clean out the CaCO3
  • Ran CT to retrieve the inflatable bridge plug. 
  • Ran CT to kick off the well and regain production. 


Success of the cement-packer job could not be achieved without handling challenges during the design and execution stages. These challenges prolonged the job.

Depth Correlation. Depth correlation is crucial to set the mechanical isolation. Here, an inflatable bridge plug was needed in the casing and the setting depth had to be accurate to avoid cement being left in the casing, which could make milling the cement difficult before retrieving the inflatable bridge plug. It is important to set the cement retainer in the tubing. In this job, the GR/CCL tool was used with a flag in the CT for correlation.

Pressure Differential. Cement slurry and seawater have different densities, which results in a hydrostatic-pressure differential. The cement slurry must be placed in the tubing/casing annulus. With cement slurry in the annulus, the pressure differential will be higher in the annulus vs. the tubing. In this job, the cement retainer was used to avoid the differential pressure and to prevent cement slurry from flowing back into the tubing.

Clean Area for Plug and Retainer Setting. The area for setting the inflatable plug and cement retainer might have been covered with debris. To ensure that the plug and retainer did not fail, high-pressure jetting was used to clean the setting-depth section to remove any debris or scale on the casing and the tubing.


By incorporating the slurry and isolation designs, cement was placed in the tubing/casing annulus without cement slurry flowing back into the tubing after pumping the cement. The correct amount of cement was pumped into the tubing/casing annulus as calculated in the design stage, and the fluid-level response in the annulus was verified with an acoustic meter. Subsequently, a pressure-bleedoff test on the annulus was conducted and the cement was confirmed to completely seal the packer leak.

This article, written by Dennis Denney, contains highlights of paper IPTC 17091, “Extending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work,” by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.