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.

In a deep water well completed with coil tubing gas lift (CTGL), significant threat on flow assurance issues has been identified due to the Joule-Thompson effect generated from the high differential pressure of the supplied gas at 3400psi with the required pressure in the well which is below 1500psi. Several wells which have low liquid rate flowing colder with the CTGL due to the Joule Thompson-effect elevated the risk of hydrate formation. Monitoring of Wellhead Temperature (WHT) alone can be a challenge since WHT is below ambient and indication of WHT increase can be interpreted as either as an increase in liquid rate or well quit flowing. The paper describes operator experience in developing an effective flow assurance scheme for prevention and treatment should the well experience hydrate related plugging and devises a strategy for contingencies and remedial actions to reactivate wells effectively without significant production deferment. A holistic approach to manage flow assurance issues in below ambient WHT deep-water dry tree wells completed with CTGL was designed, undertaken, and proven effective. Thorough investigation to analyze the root cause of the blockages along the production tubing was conducted. Several intervention options were considered with very limited clearance for the type of intervention can be conducted in the wells of concern. Decision was made to proceed with the bull-heading method via the CTGL as it was found to be the most cost efficient and quick solution. Preventive measures were then taken to avoid similar future events from happening. Three deep-water dry tree wells which was completed with CTGL were experiencing blockages in the production tubing during an unplanned shutdown. The total potential of these wells amounts to 2600bopd and warranted the team to investigate a quick solution before attempting a workover which is costly and requires longer duration for planning before execution. Two out of the three wells treated with exothermic chemical injection were successful and restored 2000bopd production. Pre-qualification testing demonstrated similar trends of pressure communication between CTGL and tubing head pressure (THP) on the successful well treatment. Chemical solution which produced heat by exothermic reaction was bullheaded into the well with immediate communication established after injection. A standard operating procedure was then developed to manage the wells under this category and prevent future blockage. Culmination of the unique approach for wells with slim tubing (CTGL) to resolve a problem should be looked at from various angles. Investigation must be conducted until the flow restriction root-cause has been identified. Preventive measures then can be taken to avoid similar occurrence which will minimize value leakages and economic impact to the field. De-risking via conducting pre-qualification and Design of Experiment based on scenarios prior to arriving at solution helps to increase chances of successful treatment.

Hydrate occurrence is synonymous in deep water wells, notably when the well experience significant reduction in fluid temperature during production. Hence, the operating philosophy must take into consideration the ability to maintain the well-fluid outside the hydrate or wax phase envelope and ensure the contingencies are in place to mitigate any plug, deposit or gel formation. This paper illustrates the characterization of hydrate and wax plug encountered and devise of innovative solution to remediate the blockage in two wells in Sabah waters which were plugged due to cooling of the wells during an unplanned shut down. The solution devised is to set precedence to manage temperature dependent blockages in similar Deepwater wells or facilities. Hydrate and wax models were created to predict blockage severity and its location. Nodal analysis was used to model thermodynamic equilibrium at target location of the plug where the temperature is below the melting point and ultimately to predict the required heat to dissolve the blockages. A Thermo-chemical system was identified, selected, and customized and then injected into well to ensure the temperature generated at the location of the plug was above the melting point of hydrate and wax. Thermo-chemical injection was identified as a viable method of In-situ Heat Generating Technique to generate heat at desired location. The chemical solution was injected via capillary tubing to transmit the heat via conduction and convection to melt the hydrate and paraffinic plug in these 2 wells. An arriving temperature of 40°C at the target zones was required to melt the plug. A positive pressure was maintained in the production tubing during chemical injection to avoid rapid pressure increase as the hydrate plugs dissolved. A temperature of 100 °C was recorded at the wellhead throughout the injection. The downhole gauge indicated positive response, suggesting the heat generated transmitted effectively. After a short duration of injection, communication was established. Hydrate inhibitor was injected to secure the well prior to unloading. The wells were successfully relieved and stabilized production of 1,200 bopd and 800 bopd respectively. The simulation was redesigned based on data collected from the operation to improve the model and to be used for future works. The ability to integrate laboratory analysis, computer aided simulation and operational data was integral to this paper demonstrating an effective way to characterize temperature dependent blockages in production system. Design of experiments provided better insight to address the problem. Innovative use of novel chemistry to produce heat, in-situ heat solved hydrate and wax related issues in a most cost-effective manner. The process of customizing a chemical system based on laboratory and simulation results was effective in ensuring delivery of the results. The bull-heading operation to inject the chemical system proved to be a cost-effective remedial method to unlock the barrels and can be considered preventive or as a contingency measure in dealing with temperature dependent blockages or plugs in future.

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