Electric Submersible Pumps (ESP) are common artificial lift equipment for boosting well productions. One of the challenges faced with ESP applications is the ESP system reliability. High percentage of ESP failures resulted from problems of packer penetrators that locate beneath the ESP packers. These failures could be attributed to the corrosion of the power delivery systems by highly corrosive chemicals and harsh downhole conditions. A method is developed to generate a low density gel system that isolates the electric connector from downhole chemicals in order to provide prolonged protections of electric connectors against corrosive environments. Mixture of low-density polymeric materials can be pumped through the bypass tubing. The mixture has lower density than downhole fluids so that it travels upwards in the wellbore. Under high temperature in the well, a rigid gel system forms and isolates the electric connector from the hostile chemicals thus providing a better protection. The rigid low density gel system was tested in the lab scale. The tested fluid system comprises of colloidal particles and thermal plastic microspheres. The colloidal particles forms a rigid gel under elevated temperature while the thermal plastic microspheres act as light weight fillers. Gelation tests are conducted under different temperature and pressure conditions. The system has a lower density than crude oil and the gelation process can be controlled by chemical concentration. Sealing effects with the presence of crude oil are tested in rusty metal pipe to imitate casing material. A wellbore injection physical simulator was also setup to observe the flow dynamics and chemical reaction that could take place in the wellbore. The field trial test was performed after a through engineering design. Coiled tubing (CT) was selected as the optimum solution for intervention and placing the fluid system. Mixture of low-density materials and gelling agent were prepared on the surface and then pumped into the targeted section utilizing 2.0" coiled-tubing (CT) nozzles. Conventional bottomhole assembly was utilized to seal the tubing section and divert the fluid system to annulus.

Matrix acid stimulation in carbonate formations can often be vital to remove formation damage post drilling and achieve a more uniform production profile. Reaching well total depth (TD) is critical for an effective treatment in extended reach wells (ERWs) completed with an electrical submersible pump (ESP). The ESP completion with minimum restriction of 2.44-in. limits the coil tubing (CT) and downhole tools size. Hydraulically powered CT tractors are an ideal solution to pull the CT to TD (Saiood et al. 2018). The completion minimum restriction only allows for 2-in. CT with 2-1/8-in. OD hydraulically powered CT tractors and a maximum pulling force of 3,200 lbs. Pre-job CT design-aided simulations predicted the 2-in. CT size and a 2-1/8-in. CT tractor would not reach well TD due to unfavorable trajectory and therefore potentially jeopardizing a successful stimulation treatment. An alternative method is to utilize 2-7/8-in. CT combined with a 3.5-in. hydraulically powered tractor to conduct matrix acid stimulation prior to installing the upper ESP completion with restricted ID. This alternative arrangement allows for a maximum pulling force of 9,200 lbs, ensuring a greater reach in ERWs and effective treatment. It also tolerates higher pumping rates with 2.875in. CT (up to 5 bbl/min as compared with 2 bbl/min for 2-in. CT), reducing the exposure time of acid on surface, reaching optimum rates faster creating favorable wormholes in the carbonate formation and reducing the pumping operation time by up to 50%. Matrix acid stimulation is then completed with the drilling rig still in position post drilling operations. Thereafter, the upper ESP completion with restricted ID is installed. This engineered solution provides an alternative for CT interventions in extended-reach horizontal wells featuring completion restrictions, where the main challenge is to maximize the reach for optimum stimulation. The approach of combining the 3.5-in. hydraulically powered tractor with 2.875-in. CT pipe successfully enabled effective stimulation of the openhole section to a 27,000-ft. TD in a challenging downhole environment.

Workover operations with conventional workover rigs have an enormous impact on the site, adding strain to operational and production targets. Alternative approaches to optimize Electrical Submersible Pump (ESP) replacements were evaluated and a Hydraulic Workover Unit (HWU) was selected as delivering the most advantageous outcome for the field to expedite the workovers efficiently and cost effectively. The HWU is more than capable to overcome any challenges and perform the replacement of failed ESP's, yet at the same time is a more compact & mobile unit than a traditional workover rig resulting in a much reduced impact on the wellsite. Several major benefits are gained including; avoidance of disruption to nearby wells, faster well turn-around, reduced cost, and ultimately an increased production avails. The size and scale of conventional workover rig and well spacing require the candidate well and other nearby wells to remove flowlines and instrumentation to create enough space for the rig and ancillary equipment. One of the primary design features of a standard HWU is the high level of accessibility in tight spaces allowing the unit to be assembled in small multiple individual components. This can be very time consuming so the challenge was to benefit from the superior accessibility but also to minimize the rig time for a more efficient process. To achieve this, a specialized fit for purpose HWU with the modular construction packaged into minimal components allowing for a swift rig up and efficient deployment of the unit. This HWU remains highly accessible and can replace the failed ESP without disturbing the installed production flowline infrastructure and instrumentation. The HWU has been a key technology enabler transforming the status quo to improve the optimization of resources and reduce operational costs. During the project of 8 pilot wells, the average workover cost reduction was calculated at 61% per well. The improvement in operational efficiency benefited from an overall 69% faster site and well preparation duration with a 13% reduction in rig time. The magnitude of these improvements in efficiency, cost avoidance and the unlocking of earlier production availability is a game changer for ESP replacement operations. The HWU equipped with comprehensive capabilities has proven itself as a viable alternative to conventional workover rigs to replace failed ESP's. The design enhancements of the pre-assembled modular construction for the HWU minimizes the hazardous and labor-intensive assembly onsite, increasing the safety environment for the operational personnel.

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