Case Study: Expanding Flow Diagnostics With Tubing-Conveyed Payload-Deployment Tool for Solid Fluid Tracer Delivery and Wellbore Cleanout
A new tubing-conveyed tool combines wellbore cleanout with multi-tracer deployment for production diagnostics and reservoir monitoring.
A computer illustration of a slick PDT.
Source: CT Evolution.
The rapid evolution of unconventional reservoirs and increasingly complex wellbore designs have enhanced the industry’s need for reliable and cost-effective methods to gather high-resolution flow data.
Production diagnostics remain central to understanding reservoir performance, optimizing completion strategies, and aiding long-term field development. Yet, the techniques available to operators often involve costly upfront capex investments, limited data duration, or logistical challenges that restrict the quality and frequency of measurements.
To address these issues, a new tubing-conveyed system called the payload-deployment tool (PDT) has been developed. The PDT (Fig. 1) introduces an innovative approach to long-term production diagnostics by combining wellbore-cleanout capabilities with the deployment of multiple solid water or oil tracer payloads in a single run.
Fig. 1—A computer illustration of a slick PDT next to 4½-in. mill PDT.
Source: CT Evolution.
Designed for reentry into single and multilateral wells, the system provides a low-impact approach to generating long-term flow data across a broad range of well environments. The PDT enables production engineers and well‑intervention teams to conduct their own diagnostic tests, comparable to completions teams, and compile key data sets for flow assurance and flow tracking for the remainder of a well’s life cycle.
This case study outlines the motivation behind the tool’s development, describes its broad functionality, and presents results from a field trial in the Lower Wolfcamp B Formation within the Permian Basin.
Industry Challenges in Flow Diagnostics
For decades, operators have relied on a combination of downhole gauges, fiber optics, chemical tracers, and production logging to perform flow diagnostics. However, each method comes with tradeoffs.
Downhole gauges provide valuable pressure and temperature measurements, but they cannot directly distinguish between contributions from individual stages or laterals.
Fiber optics provide the highest resolution of distributed acoustic and temperature sensing, but the capex and overall probability of success are challenging to replicate on a day‑to-day basis.
Liquid chemical tracers used in fracturing operations are proven but typically offer lifetimes of 3 to 6 months. Liquid tracers also face issues with adsorption and the accuracy of their delivery at the planned point in each fracture stage. Additionally, there is only one chance to perform these tracer operations during the initial fracture stimulation.
Production logging using wireline or coiled-tubing interventions can provide near-instantaneous data, but may not show a long enough data set. They are operationally complex, expensive, and usually infeasible in long-reach laterals. Adding to the complexity, most producing wells require artificial lift, which makes it impractical to run logging tools concurrently with the lift system.
Wellbore-integrity and flow-assurance issues such as sand production, scale buildup, or fracture-to-fracture communication events introduce further complications. A diagnostic method that also contributes to wellbore cleanup and flow assurance provides additional operational value.
As stage counts increase and compete for preferential flow, operators increasingly need downhole technologies that can be deployed efficiently to deliver stage-by-stage flow diagnostics.
Concept and Functionality of the PDT
The PDT was engineered to address dual challenges of data acquisition and wellbore integrity. The system combines mechanical-cleanout capability with the ability to deploy multiple solid-tracer rods that slowly dissolve in downhole environments. The system can also deliver diverters, chemicals, and other downhole products.
Key Features
1. Tubing-Conveyed Deployment
The PDT is run on either standard jointed tubing or coiled tubing, making it compatible with conventional workover and completion operations.
This approach allows for high-rate circulation during the cleanout process to ensure an open flow path once the well is brought back online.
2. Dual Functionality
The bottomhole assembly (BHA) carries down payloads inside the wellbore while removing sand, debris, or scale.
Following the cleanout and within the same run, the system allows for tracer deployment from the bottom of the BHA before tripping out of hole.
3. Multi-Payload Capability
Up to six unique solid-tracer rods can be carried in the tool.
Each tracer rod is formulated with distinct signatures, allowing operators to monitor contributions from multiple zones simultaneously.
4. Slow-Dissolving Formulation
In contrast to liquid tracers that may flush through the system quickly, the solid rods dissolve gradually, extending the tracer-release period over months or years.
This feature enables long-term, high-resolution flow-data acquisition without repeated interventions.
The tracer rods have proprietary designs that prevent them from moving once deployed.
5. Reentry in Complex Wells
The design allows reentry into single or multilateral wellbores, enabling applications across a wide variety of unconventional and conventional completions. Different arrays of tracer rods can be redeployed every few years if needed.
Operational Workflow
The PDT deployment process can be summarized as follows:
1. Planning: Up to six tracer rods or payloads are selected and loaded into the tool. Each rod is engineered with a unique chemical signature (Fig. 2).
Fig. 2—Wellbore diagram for distributed flow assurance.
Source: CT Evolution.
2. Run-in-Hole: The assembly is conveyed on tubing to the target depths, typically to the toe or deep in the lateral section.
3. Cleanout: The PDT system removes sand, scale, or debris as the tool progresses downhole.
4. Tracer Deployment: At predetermined depths, the tracer payloads are individually released into the wellbore, and the PDT is tripped out of the hole.
5. Production Monitoring: As the well is returned to production, fluids are sampled at surface facilities. The tracer signatures are detected and analyzed through time, providing a dynamic view of zonal contributions.
Case Study: Lower Wolfcamp B, Permian Basin
A horizontal well in the Lower Wolfcamp B Formation experienced multiple production challenges following hydraulic-fracture communication from offset wells and a subsequent sand packoff in the heel section. The operator required a solution that could both remediate the wellbore obstruction and acquire diagnostic data to guide future development decisions in a single run.
Deployment of the PDT
The PDT was selected for trial by an operator that planned to swap a long-stroke pumping unit with an electrical submersible pump to flow the offset fracturing water out of the system in the first few months following a workover.
The assembly was conveyed into the wellbore on tubing and advanced through the curve section. While running in the hole, the tool successfully removed accumulated sand and debris, restoring hydraulic access to the lateral.
Immediately following cleanout, solid-tracer rods were deployed at designated depths within the lateral in the same run (Fig. 3). Each rod contained a distinct chemical signature tailored for extended dissolution.
Fig. 3—First field trial tracer data set. Source: CT Evolution.
Source: CT Evolution.
Data Collection and Results
The cleanout phase restored the the well’s flow by removing the packed-off sand. Over subsequent months, fluid samples collected at surface showed clear tracer responses corresponding to the deployed rods.
The long-lasting tracer signals enabled differentiation of production contributions from multiple zones, offering higher resolution insights into the performance of individual sections of the lateral.
The trial also demonstrated the PDT’s dual functionality in a real-world scenario, confirming that both wellbore remediation and solid-tracer deployment could be accomplished in a single operation.
Running the PDT reduced the number of interventions required by half, reducing operational risk. Additionally, the solid-tracer trial provided the engineering team data needed to improve the tracer design for an extended data-acquisition period beyond what liquid tracers would typically provide.
Ultimately, the PDT demonstrated that payload delivery can be performed at any point in the life of a well.
Broader Implications and Future Applications
The successful deployment of the PDT has implications for both unconventional and conventional operations, providing flow assurance and quantitative analysis across multiple zones at any point in the well life. Looking forward, the technology has a broad set of use cases.
Unconventional Horizontals: Long laterals with dozens of stages can be profiled for longer periods of time, supporting decisions on refracturing, artificial-lift optimization, parent-child well interactions, and enhanced oil recovery.
Conventional Wells: The PDT can deploy in vertical wellbores and in stacked-pay vertical completions; operators can monitor inflow zones to understand which intervals are contributing to production.
Multilateral Openhole Wells: Multilaterals in onshore unconsolidated formations can benefit from long-term collapse monitoring from each lateral leg.
Openhole Horizontals: Areas across the lateral section of consolidated sandstone and carbonate reservoirs can be profiled for better development planning.
Offshore Directional Wells: Tracers can be redeployed in rod form using the PDT once the initial completion inflow-tracer systems deplete.
Geothermal Wells: Can provide open-loop geothermal projects with location of inflow zones with solid-tracer sweep-efficiency detection.
Water and CO2 Floods: Can provide data on sweep efficiency and inflow areas of the producing wellbores.
Unconventional Refracturing: After refracturing a well, inflow-tracer rods can be used to determine additional new stimulated reservoir volume by providing inflow data where fracturing fluids are reentering the wellbore.
CT Evolution is planning additional deployments across various basins to validate performance under different reservoir and fluid conditions. Research is underway to expand the performance and number of unique tracer chemistries, further enhancing the resolution of zonal contributions.
The rods have been updated with a new design feature to keep them static on the depths as deployed. In addition to the tracer technology, studies are underway on developing best practices for deploying diverters and chemical treatments downhole.
Conclusion
The PDT offers a new approach to flow diagnostics by integrating wellbore cleanouts with multi-payload solid-tracer deployment. The system addresses industry challenges around cost, efficiency, and data duration, while providing operational flexibility for all well types.
The case study in the Lower Wolfcamp B Formation demonstrated that the PDT can both remediate wellbore issues and provide extended flow data in a single operation. By reducing interventions and broadening the scope of production profiling, the PDT represents a valuable addition to the industry’s toolkit for reservoir management and field development.
Tyler Thomason, SPE, is the founder and CEO of CT Evolution, an Austin-based oilfield tool technology company specializing in downhole logistics. He previously served as senior vice president of operations for Rockport Energy Solutions, where he led operations across multiple assets in the Delaware, Midland, and Williston basins. Before Rockport, Thomason was senior vice president of operations for EnCore Permian Operating, helping develop a Delaware Basin asset. Earlier, as completions manager for Luxe Energy, he designed and completed 35 Delaware Basin wells and helped launch Axil Tools, which achieved profitability within its first year. Thomason began his career at EOG Resources, where he held several engineering roles supporting more than 3,000 wells across the Haynesville, Eagle Ford, and Delaware basins. He holds multiple patents, has authored a children’s book on energy, and holds a BSc in petroleum engineering with a minor in geology from Louisiana State University.
