Impact of CO2 corrosion on well integrity is an issue in mature fields of Colombian foothill wells. Concerns in regard to corrosion of casing strings having access only through the existing 7" completion challenged the use of new technology to achieve both: log corrosion on outer strings and do not suspend the well to get a full column of fluid. Therefore, corrosion monitoring was performed through 7" chrome production tubing with a new Electromagnetic Scanning Tool (EMST), in a challenging scenario: shut-in well with 3 outer casing strings with a gas cap in the upper wellbore. The job objectives were first to test the technology to detect metal loss from the outer casing strings as well as loss both inside and outside of production tubing (without pulling the production tubing) and second to establish a base line for future corrosion analysis after the immediate drilling rig intervention for sidetracking. A careful candidate selection was performed based on criticality for CO2 corrosion, completion design, service years and operating status of the well including consequence analysis to get a pilot well for EM logging. In production since 1998, the BA Y16 well was selected to be logged before a thru tubing deepening to reach two other reservoirs and further service conversion from oil producer into a gas injector well; the EMST was run in Q1 2013 and measuring the cumulative thickness up to three strings determining that no external corrosion was present in particular in the section of interest, also the high resolution image showed no presence of internal corrosion. Therefore, a successful operation was achieved meeting the proposed objectives with no HSE incidents and within budget. This technology is proven and has become a solution for further wells where CO2 or bacteria damage has been evidenced including corrosion mapping through chromed and carbon steel in a single run avoiding the excessive costs related to pulling the completion to get access to the outer casing strings.

Pumping sand through coiled tubing (CT) with real-time capabilities is not a common practice because of potential risks associated with cable integrity. A successful sand plug settling procedure supported by a real-time fiber-optic integrated system under critical well conditions was of high importance during a recompletion intervention, allowing optimization of time and costs. Multiple methods are used to isolate a well during recompletion activities; nevertheless, a cost-effective method to divert involves setting sand plugs with CT and a real-time fiber-optic integrated system, which is essential to achieving precise settlement of the sand, not just for depth but also for volume of sand pumped. Without this complete system, the operator would need to make extra runs for correlations with electric line (e-line) or CT units, which increases both cost and operational time. A real-time fiber-optic integrated system allows adjustment to the sand plug stages in real time to help ensure top of sand (TS) necessary to isolate the producer formation and keep out the wireline entry guide without additional runs and increased costs. A casing collar locator (CCL) tool permitted the correlation depth to be measured in each tag, ensuring knowledge of where the sand was placed and helping prevent incorrect depths resulting from uncontrollable factors, such as elongation. More than 6,500 lbm of sand was pumped through CT using a real-time fiber-optic integrated system without losing communication with the downhole tools and without affecting cable integrity, which could lead to bird nesting the cable because of high friction and excessive slack inside the pipe. This real-time fiber-optic integrated system begins a new generation of sand plug operations by helping prevent additional runs or having other units correlate, particularly if a recompletion activity is programmed and space accommodation is a challenge because of the workover unit.

Underbalanced perforating with conventional cable operations involves several risks associated with well tortuosity, cable tension capacity, gun lifting, and the capability of achieving the optimum underbalance for effective tunnel cleanup (Graeme et al. 2008). Because of these risks, an operator in Colombia elected to perform a perforating operation using a coiled tubing (CT) real-time fiber optic (RTFO) integrated system in a newly drilled development well. CT-conveyed perforating is ideal for this type of wellbore. To achieve the proper underbalance and depth correlation to perforate the target interval, an RTFO CT system provides the most accurate and reliable depth correlation process, in addition to real-time pressure and temperature monitoring inside the CT and the outer annulus. Using the RTFO CT system, only two runs were necessary to complete the perforating program, in accordance with the operator design, rather than performing an additional run needed for pickling and to generate underbalanced conditions. The use of the RTFO CT system can help to prevent correlation errors resulting from CT elongation. A CT structure was not necessary to deploy the guns based on the finite model analysis that calculates maximum stress and flange bending, including a safety factor. A hydraulic firing head can be used with an RTFO CT system to activate the guns without affecting the integrity of the fiber optics or the downhole sensor tool after detonation. The RTFO CT system enabled the operator to evaluate the reservoir potential. The evaluation results indicated that one of the zones is a low producer, which avoided the pumping of unnecessary nitrogen to induce the specific zone. The use of a downhole pressure sensor enabled the identification of the time at which the guns were detonated. Improvement to the rigup was evidenced and enabled time optimization without affecting the operation. The casing collar locator (CCL), used for depth correlation, was a crucial factor in reducing operational costs because it helped to optimize placement accuracy and gun detonation and to prevent misfiring (Newman 2003). The guns were successfully activated without nonproductive time (NPT) or health, safety, or environmental (HSE) incidents during operations. A successful perforating operation was completed with 4,000 psi underbalance in a new formation using hydraulic detonation with continuous real-time downhole condition monitoring before and after detonation, enabling the operating company to make decisions in real time. This new approach of using an RTFO CT system combined with the hydraulic firing head can be used to perforate new formations in these crucial scenarios (wells with production greater than 20 MMscf/D and zones with continued sand production).

A Coiled Tubing Gas Lift (CTGL) pilot project was implemented in a reservoir with a compositional fluid system in the Casanare foothills area in the northeast of Colombia. This paper presents the life cycle of the project from design to operation including production test results after installation to "revive" wells with high water production and very low gas liquid ratio. High pressure gas was injected through conventional 1-3/4" and 2" 110 Kpsi coiled tubing, installed inside completion strings and hung to the Christmas tree to reduce cost of the project and avoiding recompletion of the well in a low-cost environment. A pilot project included three well was executed ending 2015, being a world first CTGL for 1-3/4" and 2" CT deployment beyond 12,000 feet. Challenges for deployment of CT string, well control aspects, barriers for control upon disabling of DHSV and master hydraulic valve among of moderate CO2 corrosion impact were some of the risks associated to this project. A pilot installation on three wells was successful and this paper compiles lessons learnt from this process including candidate selection, deployment, material selection, well intervention and risk assessment among of operational performance and pipe recovery after end of project life.

To measure and analyze reservoir pressure, conductivity, gas/oil ratio (GOR), and skin value, it is necessary to run a pressure buildup (PBU) test to the corresponding zone of interest in the well. This paper describes how the implementation of a coiled tubing (CT) real-time fiber-optic (RTFO) integrated system and a retrievable packer were determining factors to successfully develop both PBU in an upper formation and a pressure evaluation in the lower formation in the same run. To help ensure isolation and evaluation of each high potential zone in the well, conventional methods involve multiple procedures requiring multiple runs. Using the CT RTFO (Vera et al. 2018) integrated system with a retrievable packer, only one run was necessary to complete the PBU program, which involves the isolation and corresponding log of two reservoirs. This new technology helped the operator overcome challenges and deliver improved service quality. Real-time data acquisition during the packer setting helps ensure correct inflation, and continuous monitoring of the isolated zone during the PBU process helps ensure data accuracy and defines the end of data acquisition time once radial flow has been observed in the pressure transient analysis; therefore, the points previously discussed strongly impact production by optimizing operation time. Avoiding the use of materials such as cement to isolate the mentioned zones made this operation environmentally friendly. The greatest value of this technology is that it makes real-time monitoring of both the upper and lower zones possible at the same time. The PBU test was successfully developed by determining reservoir pressure, skin, and flow regime of the near zone formation with precision and confidence, which helps the operator make decisions about future stimulations. High-pressure stimulation was achieved, which resulted in 460 BOPD over the initial production. Finally, a downhole ball-drop tool was effectively used to help ensure that packer setup was accurate and to reduce intervention time.