A rigid riser system has been designed, built, and proven as an effective method to conduct coiled tubing operations on floating platforms. This system is installed above the Christmas tree which is supported by the platform's production riser and riser tensioner system. The rigid riser set up is a passive system that does not require the use of a crane or other mechanisms to support or hold up the coiled tubing injector head during operations. The axial load resulting from the weight of the injector head, coiled tubing, and snubbing/pulling forces on the pipe are carried in compression through the rigid riser to the tree and wellhead. The excess capacity of the top tensioner riser (TTR) supports these loads while allowing for relative motion due to tide, waves, and platform motion. The rigid riser system uses a purpose-built, heavy-wall riser and a spider beam insert to resist buckling effects and bending moments. In practice, this system has improved the rig-up time and mitigated HSE issues as compared to the conventional motion-compensated lift frame method. In addition, the system has a support frame that increases the rigidity of the injector head and accessories, resisting the excessive bending and torsional loads imparted by back tension and movements of the coiled tubing (CT) reel. An engineering study was performed to determine the dynamic loads and stresses for the various operational and contingency conditions on all the components of the rigid riser system and to confirm sufficient capacity of the TTR system. The rigid riser system has proven to be a safe and cost-effective solution for coiled tubing operations from a floating platform compared to current motion-compensated jacking frame systems. Coiled tubing well interventions were executed using the rigid riser system, and the operational results have been convincing. The passive nature of the system provides an HSE advantage by eliminating mechanical or human intervention during operation. This paper reviews the design aspects of the rigid riser system, its advantages over the current coil tubing intervention systems, and the operational results after executing the coiled tubing interventions.

Installing an electrical submersible pumping (ESP) system in an oil well is one of the optimal artificial lift methods to increase production and maximize ultimate recovery. However, installing and retrieving an ESP using an offshore rig is costly and presents planning challenges. In some geographies and projects, offshore intervention rig costs and risks sometimes outweigh the potential gains of an ESP system. An operator in Malaysia was interested in installing an ESP system in an offshore well to maintain production rates, but the intervention costs were a roadblock. The challenge was to devise a rigless ESP deployment system that can be deployed through the existing completion to avoid the need for a rig, even on the initial deployment. The system would need to provide a 2000 BPD flow rate to justify the initial investment of the wellhead modifications, surface equipment, the newly developed rigless-deployed ESP system, and completions accessories. This new generation rigless-deployed ESP system features an inverted ESP with the ESP motor on top, connected directly to the power cable. This revolutionary design eliminates the motor lead extension, removing the weakest connection in traditional ESP systems. The rigless deployed ESP system enables deployment under live well conditions, eliminating the need to kill the well and the need for a rig – inclusive of the initial deployment. This paper reviews the design and deployment process of the first installation in Southeast Asia.

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Due to sand production coming from the upper zone of a multizone monobore gas well completion, the well production had to be choked back to a flow rate below the well's maximum sand free rate (MSFR). This resulted in suboptimal production. A straddle packer assembly was installed across this upper zone, which isolated the sand production and, therefore, enabled the choke to be removed and the well production to be increased to its true, optimal capacity. Several previous attempts to deploy and install the straddle components at their required depth using the prescribed slickline deployment method proved unsuccessful, because of hold ups that occurred while running in hole—due to a well trajectory of 72 degrees deviation and 4.579 deg/100 ft dog leg severity, coupled with the small tubing inside diameter (ID) associated with the slim 3 ½ in. completion. Furthermore, it was found that insufficient forces were available via slickline deployment to execute the related stabbing, setting and release actions required during in-well straddle component installation, because of the limited jar down weight available and safe working load limits on the slickline at the setting depth. As a result, a slim 2 ⅛ in. electric line tractor was utilised, in combination with a 2 ½ in. electrohydraulic linear actuator (stroker). The tractor conveyed the various straddle packer and spacer elements (straddle tubes) to depth and the stroker installed these components in the well to confirm their engagement and to ensure their controlled and confirmed release. Being bi-directional by design, the stroker provided both the upward and downward forces required for component installation—stabbing, setting, and pin shearing to release. The stroker was also available in the toolstring in case of any inadvertent tool sticking encountered while running in hole due to the well trajectory and produced sand debris. A system integration test (SIT) was meticulously planned and executed by the relevant operator and service company representatives before the operation. It was used to confirm the stroker's capability to stab and set the straddle tube into the lower packer and to shear the running tool used to install the straddle tubes and upper packer. This included the installation of straddle tubes into the lower packer section, done in a horizontal configuration and completed using higher setting and pulling forces than those expected during the actual job to ensure more than adequate forces would be available. The operation was executed successfully following the newly defined program, applying the lessons learned from the SIT. A total of four runs were carried out using the combined tractor/stroker deployment string configuration without any in-well deployment issues—the straddle component installation completed with 100% operational efficiency. Following this, the well was put back onto production and the production rate increased from approximately 1 million standard cubic feet per day (MMscf/D) to 3 MMscf/D, with no sand production observed at surface. Having not been done before, this methodology proved to be a successful option for the operator for straddle packer assembly deployment in deviated slim wells.