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Following the rig-based well testing stage, completion programs of high-pressure wells in North Kuwait call for well killing with heavy oil-based mud (OBM). The workover rig is then demobilized, and production flowlines are installed. Well activation plans are carried out riglessly, and coiled tubing (CT) is instrumental to bringing the wells back to sustainable production. One of the major drawbacks from this practice is the formation damage generated by the OBM, which often requires additional interventions for remediation. To address this limitation, a new approach leveraging instrumented CT for temporary well suspension was recently implemented. Real-time downhole telemetry is enabled by an optical line installed in the CT pipe and used to accurately set a through-tubing inflatable packer (TTIP). Once the latter is anchored at the planned depth, above the interval open to the formation, CT is disconnected from the packer assembly, and the fishing neck is protected with a sand plug. CT is then retrieved to surface, and a slickline dump bailer is run to spot cement on top of the sand plug. Once the cement has set, CT is run to displace the wellbore to kill fluid. Two pilot wells were selected to implement this new approach for temporary well suspension. Both wells had a maximum potential wellhead pressure in the order of 7,400 psi, and 15.0-ppg OBM was originally planned for well suspension purposes. Upon completion of the zonal testing program - which included initial stimulation, well activation, and flowback - instrumented CT was run with high- pressure rotary jetting to condition the TTIP setting depth and displace the wellbore with brine, after which, a shut-in wellhead pressure near 2,000 psi was observed. In the next CT run, TTIP was set close to the end of the production tubing, and critical stages, such as depth correlation, packer inflation, and packer anchoring testing were closely controlled via real-time downhole measurements. Additional verification of the TTIP effective seal was carried out before the CT was disconnected from the packer assembly through an inflow test relying on live downhole pressure monitoring. Once the TTIP released, the temporary suspension was completed following the methodology described above. Finally, the wells were observed at surface with zero pressure for more than 24 hours, receiving acceptance from the operator. This alternative approach for temporary well suspension represents an innovative solution to bring wells back into production without additional restimulation or well activation. This methodology greatly relies on CT real-time downhole telemetry, and operators from the Middle East can benefit from the experience gained in this project.

Many unforeseen circumstances can occur when coiled tubing (CT) is deployed into a well with differential pressure sticking being one such potential problem. Diagnosing wellbore data before operating on a well is important but does not eliminate the possibility of stuck CT. With the increase in use of CT on wells with extreme conditions, the requirement to find solutions that can help retrieve the CT and its bottom hole assembly (BHA) is crucial. When using conventional CT equipment, the operator will have access to several parameters, such as weight, circulating pressure, wellhead pressure (WHP), and depth. However, all these are surface parameters, meaning they are obtained based on the surface conditions. Having accurate downhole information to accompany the surface data can be much more helpful when encountering differential pressure sticking situations. This paper presents the application of real-time hybrid CT (RTHCT) technology to overcome stuck CT. The technology incorporates a 4mm hybrid cable injected into a CT string and includes a modular sensing bottom-hole assembly (MSBHA) providing key downhole information. Internal and external pressure and temperature, casing collar locator, gamma-ray, compression, and tension are all examples of the downhole data. A flow-through camera was also added to the BHA to provide 360° visibility in the multilateral well, resulting in a high-value BHA with a total length of approximately 36ft. The RTHCT technology was initially utilized to stimulate a multi-lateral well composed of 2 legs. The CT became stuck while displacing L1 lateral, which had 6-1/8in internal diameter and 2,647ft lateral length. The reason the CT became stuck was ambiguous. But upon careful evaluation of the wellbore information, it was determined that it was likely due to the differential pressure because L1's lateral open-hole section had a large variance in reservoir pressure (up to 680psi difference). This paper presents some lessons learned when encountering a stuck CT scenario and the benefits of utilizing the RTHCT technology in challenging well conditions to successfully retrieve the CT. With the RTHCT technology, the bottom hole pressure (BHP) was determined allowing the downhole sticking point to be estimated. Higher overpull values were then applied along with additional pumping whilst remaining within the operating limits of the BHA.

Drilling a multilateral well is generally recommended for several reasons such as achieving higher productivity indices and improving recovery in tight, low-permeable zones. While the many benefits of multilateral wells are attractive, they also have drawbacks which make these wells challenging. A key challenge is how to effectively stimulate all the laterals after they have been drilled. This paper presents the application of a unique intervention technique in a multilateral well to stimulate several laterals in a single run. To increase reservoir contact area the operator drilled a multilateral well composed of 4 legs. This was carried out despite the absence of proven ways to stimulate each lateral individually. This intervention would also present the following challenges: Well displacement and stimulation would require multiple re-entries into each lateral, all conducted from a drilling rig. All the laterals were known to branch off from the low side of the bore, so individual lateral and main-bore selection would be complex. Extended reach laterals require accurate friction lockup modelling and mitigations. The unique solution presented in this paper includes the use of real-time Hybrid cable coiled tubing (RTHCT) technology. This incorporates a hybrid cable installed in the coiled tubing (CT) string and a modular sensing bottom-hole assembly (MSBHA). Electrically controlled indexing tool, inclination sensor, tool-face sensor, and hydraulic knuckle joint were used as part of the BHA to enable real-time diagnostics and dynamic controls from surface to successfully enter the lateral legs. The MSBHA enabled the orientation of the BHA electrically to any position required using software to determine and control the exact position of the BHA. This paper presents a solution to all the above-mentioned challenges. It discusses the successful implementation of the RTHCT to displace and stimulate all the 4 laterals in a single CT trip in less than seven days, pumping over 7,000 bbls of various chemical systems and covering an open-hole length of 11,176 ft. Unlike other technologies, the RTHCT technology confirmed entries into the laterals without the need to tag the bottom of the lateral, saving substantial time. Enabling re-entry in these 4 laterals represented a world record translating into major efficiency improvements and cost savings for the project. This intervention also represented the first time in Kuwait that more than 2 laterals have been accessed in a CT run.

The effectiveness of stimulation using hydrochloric acid in high permeability, fractured carbonate reservoir is a challenge due to several reasons like fast acid spending rates, high leak off and non-effective diversion. All these limit the success rate of matrix stimulation using hydrochloric acid. Ultimately the communication between reservoir and wellbore will be less optimum leading to less than expected well performance. The industry is in continuous search of an effective stimulation technique through which good communication between reservoir and wellbore can be established. In the pursuit of maximizing oil production, Kuwait Oil Company is implementing various new technologies. Recently, acid tunneling technology was piloted in an old producer well in one of its prolific yet challenging Mauddud carbonate reservoir. Acid tunneling is a new approach of stimulation that supersedes normal matrix stimulation in carbonate reservoirs to enhance reservoir contact by creating tunnels through dissolution of rock in acid. Mauddud is a super-giant depletion-drive oil reservoir in NK field undergoing massive development efforts with enhancement in oil production through phased pattern-water flood. The reservoir has 10 layers and the average permeability of the reservoir ranges between 15 md to 1D predominantly due to fractures and vugs, which are distributed and extended variedly from layer to the other. The acid tunneling pilot was performed in an old well in Mauddud limestone located in south-eastern part of Raudhatain field where the rock quality is poor compared to the crestal area. The well was selected for pilot due to poor production. The well does not enjoy injection support due to a sealing fault between it and an injector, lying a kilometer away. The well penetrated three layers A, B and C in Mauddud. Two tunnels of 25 ft each were created using 15% HCl acid. The well showed good production after acid tunneling job and the productivity index of the well increased three times. The well is still showing good performance even after one year. These pilot results lead to full scale field implementation of this technology. The paper presents a case study describing advantages of acid tunneling, well selection criteria for this technology application, selection of effective acid concentration for the job and also limitations of the technology. All these informations work as a guideline to implement this technology in mass scale.