Wells in the Vaca Muerta field have consistently hosted an array of technical challenges from downhole conditions in the extended lateral section, including casing collapse or restrictions developed during the hydraulic fracturing phase. With these factors in mind, an initiative was made to implement key operational parameters to improve efficiency during Coiled Tubing (CT) operations without sacrificing (Health, Safety, and Environment) HSE or (Service Quality) SQ during the completion life cycle associated with unconventional activities. Operational optimizations based on ongoing diagnostic, design and delivery of CT well interventions are shown in this paper through a chronological compilation of 45 wells in 12 pads. Initially, CT milling job times were defined based on the minimum and maximum speeds while running in and pulling out of the hole, circulation fluid parameters to ensure turbulent flow and parameters for gel sweeps and wiper trips. Subsequently, a series of reviews of the data collected from operations was implemented, and the focus was shifted to operating times at the different job stages. This was followed by stream mapping the personnel and equipment assigned to each specific activity. Additionally, Key Performance Indicators (KPIs) were defined, such as CT speed between the surface and the kick-off point, average speed between plugs, plug milling time, and time to return to surface while pulling out of the hole. This journey to efficiency has been achieved by systematically introducing continuous improvements into our operations, utilizing on-site field personnel as the main driver and the engineering team as support, monitoring the execution, and taking action when needed. After servicing 45 wells across 12 locations over two years, an 11% reduction of the total time in the well during frac plug mill out has been achieved. Considering that the lateral length of the wells and the number of stages has increased by 52% and 41%, respectively, this has enabled significant cost savings in a safe and effective way. Operational efficiency has to be aligned with contemporary advances in the industry. As completion strategies evolve, so must our intervention methods. This paper documents how the completion life cycle of wells in a challenging, unconventional environment has been reduced through customized well interventions with CT.

This paper will present planning and execution details for different mechanical plug types used to prevent fluid loss and formation damage during workover interventions on deepwater wells with extreme hydrostatic overbalance conditions, between 2,000-2,200 psi. Actual case history for four wells, using different mechanical formation plug methods, from one deepwater field in the Gulf of Mexico will be included. The information is applicable to oil producing wells, to be worked over with similar extreme hydrostatic overbalance to producing formations, where well control needs to be maintained during the intervention, fluid loss to the producing formation needs to be minimized and subsequent removal of the isolation barrier is required to restore well production. The results obtained with all four different isolation methods used, suggest that a detailed assessment to the well conditions, along with "fit-for-purpose" shop tests simulating the specific well conditions, has to be completed prior to selecting the most convenient option to execute the workover. This paper will describe the specific planning and operational process of the workover activities, and present a number of lessons learned and useful recommendations for similar activities in extreme hydrostatic overbalance wells.

The first production log ever run in a heavy oil, long horizontal well completed with premium screens in open hole and through a Y-tool was successfully executed by Petroregional del Lago S. A. (a joint venture between PDVSA and Shell) in the Urdaneta West Field (Lake Maracaibo, Western Venezuela). The purpose of the job was to identify the origin of water in a well that experienced water break-through from the first day of production. A specialized set of logging tools was run to detect both water and oil flow, as well as to determine any flow behaviors like cross-flow that would help understand the source of water in the formation, obtain sufficient data to prepare a water shut-off program, and establish basic productivity information from the well, being this also the first production log run in the heavy oil wells in the field, which require artificial lift to flow. The results of the production log indicate that a sand package is producing water from an unexpected zone, which will require a water shut-off workover. This paper describes the planning, operational and interpretation processes of the logging activity, and presents a number of lessons learnt and useful recommendations for similar activities in heavy oil wells. Introduction Petroregional del Lago S. A. (abbreviated PERLA) is a joint venture between Petroleos de Venezuela S.A. (PDVSA) and Shell International Exploration and Production (60% and 40% share, respectively). The company operates the Urdaneta West Field, located in Lake Maracaibo in west Venezuela. The field has three producing reservoirs, with very different geological characteristics and well types. One of these reservoirs is the Misoa formation, which is a Miocene formation consisting of unconsolidated sands and containing very significant reserves of heavy oil. The main characteristics of the Misoa Reservoir are summarized in Table 1. The well UD-785 (MIB-10) was drilled as a heavy oil producer in the Misoa formation and completed with an Electric Submersible Pump (ESP) completion with a Y-tool. The Premium screens (mesh type construction) were installed in the reservoir section, in open hole. The well was not gravel packed. The final completion diagram is shown in Figure 1. The well was started to production with the ESP, and in the first day of production the water cut stabilized quickly to 98%. The salinity of the produced water was measured and was found to be equal to the known formation water. The well initially produced at a rate of 2000 bbl/day for 5 days, and it was shut in to avoid operational problems associating with handling the produced water at the tank terminal. The initial well test evaluation indicated a big productivity index of 13 bbl/day/psi, one order of magnitude above the expected productivity based on the logs. A down-hole multi-sensor was installed with the ESP assembly, so data was available of the different pump parameters. The pump intake pressure measurements indicated a higher than anticipated reservoir pressure, with a fast build up period after the well shut-in. The geological and petrophysical analysis of the open hole logs obtained with LWD tools indicated that a stratigraphic marker that had never been drilled before in the area had been penetrated. The normal porosity, resistivity and shale content cut-offs used in the reservoir were applied to the logs in this section, indicating the presence of oil, but also of higher that typical water saturation. This sand package became the main suspect for water production. See Figure 2.