Ecopetrol

Abstract This paper presents design improvements, performance results and lessons learned from deploying deep (≥14,000 ft) coiled tubing-based artificial lift systems – velocity strings (VS) and coiled tubing gas lift (CTGL) – in mature gas-condensate wells of the Piedemonte Basin. These rigless interventions were implemented to mitigate liquid loading, maintain production in high-pressure environments, extend the economic life of critical assets, and assure gas supply to meet market demand. Candidate wells were selected through nodal analysis and production forecasting to anticipate critical velocity rates. VS systems were installed using coiled tubing to reduce liquid holdup and restore flow in low-rate wells, while maintaining functionality of the tubing retrievable downhole safety valve (TRSSV). CTGL systems were installed in wells with moderate to high liquid production (>1,300 BPD), where gas injection was available. Multiple configurations—stainless steel (~19.9Cr) and carbon steel coiled tubing combined with dual-flow safety valves and different BHA designs—were evaluated to assess performance, corrosion rates, run life, and reliability under CO₂ conditions with paraffin deposition tendencies. The implementation of coiled tubing based artificial lift systems was carried out in two phases. First, from 2016 to 2020, early pilots of VS and CTGL faced operational and material challenges, including corrosion-related failures, paraffin deposition, and limited run life, resulting in low economic returns. These experiences provided critical insights and lessons learned such as:-Early Intervention is critical: Installing VS or CTGL before loss of lifting capacity significantly improves success and production rates.‒Hybrid flow configurations: Allowing flow in multiple ways as only coiled tubing, annular coiled tubing-tubing, and only annular enhances flexibility.-Material selection matters: Using Stainless Steel (19.9 Cr) Coiled tubing mitigates corrosion in high-CO2 environments-Operational adaptability is essential: Addressing paraffin buildup and gas injection rates through designs and field iterations improves system performance.-Candidate selection and planning: Proactive identification of wells and standardized designs reduce costs and intervention time. Building on these lessons, VS and CTGL installed during 2020-2025 achieved a success rate of 80% for VS and 100% for CTGL. A total of 11 VS and 15 CTGL were deployed, extending well life by 18-24 months for VS and 36-48 months for CTGL, delivering 6.3 million BOE of incremental recovery. This paper presents a replicable model for extending mature gas condensate field life using coiled tubing technologies tailored to liquid-loaded gas wells. It contributes new insights into rigless deployment strategies, material optimization, and adjustments for HPHT environments. These findings advance the state of knowledge on artificial lift, offering a scalable solution that supports energy transition goals through enhanced gas recovery.

Abstract The operations of in situ combustion (ISC) projects are among the most challenging enhanced oil recovery (EOR) methods commercially available. This study focuses on the Chichimene Field ISC pilot updates, including the incorporation of the air-water alternating (AWA) injection scheme and the implementation of three chemical treatment pilot tests to assess H2S management, corrosion, and scaling tendencies. This paper will also present possible strategies to manage produced gases to reduce the carbon footprint associated with the potential expansion of the ISC project. The Chichimene ISC pilot performance is presented in terms of incremental oil rates, air-to-oil ratios (AOR), and air-to-water ratios (AWR) for both dry and wet air injection schemes. The combustion front propagation is monitored in real time through Distributed Temperature Sensing (DTS) temperature profile measurements across the entire gross pay interval of two observation wells located approximately 200 ft from the injection well. The evaluation of the new chemical treatment strategies at pilot scale is based on a comprehensive analysis of fluid composition (gas and water) and chemical dosage over 13 to 20 months. Finally, the total gas production and its composition were used to infer possible management strategies of the produced gas from the ISC pilot expansion (Flue Gas or CO2), based on full-field numerical simulations. As of June 2025, incremental production has exceeded 2.7 million barrels (bbls), with certified contingent oil resources of 915 million barrels of oil (MMBO). The AWA injection strategy suggests an increased sweep efficiency, based on the temperature distribution of both observers and additional incremental oil (> 0.120 MMBO), while maintaining an AWR below 3,000 scf/bbl. The pilot evaluating the H2S scavenger demonstrated that a non-nitrogenated overperformed triazine, maintaining H2S concentrations below 400 ppm, reducing the dosages (30-50%) and up to 50% in cost treatment per barrel (from $US 5.2/bbl to $US 1.93/bbl). Additionally, the chelating capabilities of the new H2S scavenger (glycol-based) also contributed to reducing the dosage of the scale inhibitor (from 500 to ≈100 ppm). The third chemical treatment pilot demonstrated that the encapsulated dual-functional corrosion and scale inhibitors represent the most effective treatment strategy in a low-water-saturation reservoir compared to capillary or batch injection. Finally, the main challenges of the ISC expansion are managing the produced flue gas or CO2 (storage vs. EOR/storage) and ensuring a sufficient power supply to support large-scale field implementation. Assessing the impact of flow assurance strategies in EOR projects is generally overlooked. This study provides key insights into monitoring strategies for adjusting chemical treatments as the displacement front advances, thereby improving project economics. This study also provides valuable information for integrating CCUS strategies into thermal EOR processes.

This paper reviews the use of nanotechnology in stabilizing asphaltenes, a critical challenge in improving oil recovery in mature and high-viscosity reservoirs. We explore the application of nanofluids and nanoparticles to prevent the precipitation of asphaltenes and enhance the stability of oil-water emulsions, reducing the risk of formation damage. The study synthesizes experimental findings from various nanotechnology-based treatments, comparing them with traditional asphaltene stabilization methods. The paper also discusses how nanoparticles alter the flow properties of crude oil by modifying the surface chemistry of asphaltenes, thus improving oil mobility. Furthermore, we review the impact of nanofluids on enhancing the recovery factor in reservoirs affected by asphaltene precipitation and the role they play in mitigating operational issues such as paraffin wax deposition. The study concludes by presenting a conceptual framework for integrating nanotechnology into enhanced oil recovery (EOR) strategies, focusing on the stability, efficiency, and long-term applicability of nanofluids in asphaltene stabilization.

Abstract Well integrity problems in production and injection wells are becoming more frequent every day. These well integrity problems could have environmental consequences such as contamination of shallow aquifers suitable for human consumption, crossflow of fluids produced from the reservoir that can migrate to the surface behind the casing, causing an imbalance in the ecosystem. The objective of the work is to detect and quantify the Velocity and direction of the fluid behind casing using DAS and DTS fiber optic systems during transition periods to mitigate environmental risks. The work methodology consisted of deploying a fiber optic cable and logging DAS and DTS data in the time domain throughout the entire interval of the well, monitoring the flowing and shut-in pressures on the surface. Fiber optic data was obtained in two flowing and two shut-in conditions, with the objective of studying the shut-in to flow and flow to shut-in transition periods. Processing of the DTS-DAS data was carried out and thermal and strain changes were evident in both the DTS and the low-frequency DAS or slow strain [<1Hz]. Acoustic responses could also be observed in the high frequencies of the DAS RMS [ 1-2500Hz]. In the graph of the depth (D) vs the time domain (T), an abnormal behavior of the fluid movement inside the tubing and behind the casing was clearly observed. This behavior was analyzed as a vector, and the fluid velocity was determined with the first derivative of the depth function with respect to time (v=dD/dT). The results and findings of the fiber optic work with DTS-DAS were compelling in terms of fluid movements within the tubing, annulus and behind casing in wells with integrity problems. The DTS-DAS quantified the velocity of the liquid column in the tubing and annulus and described its vertical trajectory until stabilizing at a particular depth. In the wells that had annular pressures (CHP) which indicated integrity problems, due to the fluid migrating to the surface, the DTS-DAS was able to identify the depth of origin of the leak, as well as the direction, and the fluid velocity behind casing. The DTS-DAS showed cross flow between active formations, this fluid moved behind the casing, and as a result the fluid direction and velocity was calculated. Finally, the DTS-DAS fiber optic technology can monitor the behavior and vertical trajectory of the fluid moving behind the casing and within the tubing, determining the direction and magnitude of fluid velocity, where previously other technologies could not determine it. Based on the results obtained, assertive decisions can be made in a short time that allow intervention in the well to increase hydrocarbon production and mitigate environmental risks.

Abstract Over the last five years, four different wells presented an integrity issue related to failure of at least one of the primary barriers of the completion and risk was estimated high (H). This work presents a comparative analysis of integrity remediation strategies in high-risk gas wells, focusing on cost-effective and environmental impact (CO2 emission) by comparing Rigless-Rig operations. The study reviews four field cases: one rig workover and three rigless interventions, each one involved integrity deviations such as annular communication (>2000 psi), loss of barrier effectiveness, and risk of collapse. Rigless solutions included cement and resin-cement plugs tailor-made for high pressure (>4500 psi), high temperature (>270°F) conditions, annular isolation above packers, nitrogen assisted cleanouts and contingent stimulations. Integrity diagnostics, operational planning, lab tests, and post-job evaluations were analyzed to assess effectiveness, risk mitigation and production recovery. The methodology integrates pressure testing, production data, costs, and CO2 impact to validate the outcomes. The first well intervention was completed with a workover Rig, the tubing string was pulled out of hole, casing integrity was restored using a casing path and the well was re-completed with a new tubing string. However, this required extensive logistics, high costs, high footprint and prolonged downtime of the well. To find a cost-effective solution rigorous laboratory testing along with coiled tubing simulations were carried out. The lab and simulations results enabled a rigless intervention to restore integrity of the barriers, using E-Line for connecting tubing-annular and coiled tubing to place resin-cement slurries directly into the annular sections, achieving dual barrier isolation with minimal footprint. Field operations proved to be successful in restoring well barriers while being more cost-effective, reducing NPT and HSE exposure. This paper introduces a framework for selecting rigless integrity remediation over traditional workovers. These case studies support broader adoption of rigless strategies in integrity management, especially in mature fields where cost and sustainability are critical.