bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantification of Gas Exsolution Dynamics for CO2/CH4-Heavy Oil Systems with Population Balance Equations
Authors: Dong Xiaomeng , Zhao Zulong , Yang Daoyong , Jia Na 
Published: March 2024

Abstract
Although foamy oil phenomenon has been considered as the key factor that dominates heavy oil recovery, the existing models cannot be used to accurately quantify gas exsolution dynamics in foamy oil under various conditions due to the inherent physics and complex flow behaviour. In this study, experimental and theoretical techniques have been developed to quantify gas exsolution dynamics of CO2/CH4-heavy oil systems while considering gas bubble nucleation mobilization, and binary coalescence. Experimentally, constant composition expansion (CCE) tests were performed with a sealed PVT apparatus for the CO2/CH4-heavy oil systems to induce foamy oil behaviour by gradually depleting pressure at a constant temperature, during which the pressures and volume changes were monitored and recorded continuously. Theoretically, the Fick's law, equation of state, classical nucleation theory, and population balance equation have been integrated to describe the gas exsolution dynamics, during which gas bubbles are discretized with the fixed-pivot technique. The gas bubble number and size distribution in the induced foamy oil can then be determined once the deviations between the measured and calculated parameters, including liquid volume and pseudo-bubble point pressure, have been minimized with the genetic algorithm. For both CO2- and CH4-heavy oil systems, not only can a reducing pressure depletion rate or an increasing temperature result in a higher pseudo-bubblepoint pressure, but also gas bubble growth is strongly dependent on both temperature and diffusion of a gas component in heavy oil, while increasing the solvent concentration in the heavy oil tends to hinder the gas bubble nucleation and mitigation due to the higher pressure set for the experiments. During the generation of foamy oil, a higher temperature reduces heavy oil viscosity to accelerate the diffusion process, positively contributing to the gas bubble nucleation, binary coalescence, and bubble mobilization, respectively. Compared with CO2, CH4 induces a stronger and more stable foamy oil, illustrating that, at a lower temperature, foamy oil is more stable with more dispersed gas bubbles. In this study, the newly developed theoretical techniques are able to reproduce gas exsolution dynamics at the bubble level, allowing us to seamlessly integrate them with any reservoir simulators to not only accurately characterize foamy oil behaviour, but also evaluate the associated recovery performance.
A Quick Decline Method for Forecasting Multiple Wells Using Sparse Functional Principal Component Analysis
Authors: Hamdi H , Zirbes E , Clarkson C. R 
Published: March 2024

Abstract
Accurate production forecasting for multiple wells that have both sparse and irregular measurements concurrently is a challenging task. Type-well analysis is commonly employed to model the average decline behavior of a group of wells from empirical relationships. The modeled type-well represents the behavior of a typical well in the studied reservoir. However, modifying the type-well to forecast individual well data is difficult. In this study, sparse functional principal component analysis (FPCA) is utilized to accurately forecast production from multiple wells simultaneously from the systematic statistical trends inferred from the group of wells.
Sparse FPCA analyzes an ensemble of irregularly-sampled timeseries to describe the underlying random process (RP) using the decomposed components. As such, one can sample from the estimated RP and generate a smooth and regularly-sampled timeseries. The sparse FPCA is primarily an interpolation method where the reconstructed timeseries could not reach beyond the horizon set by the ensemble length. However, with the proposed approach in this study, the decomposed components of FPCA are extrapolated using an autoregressive integrated moving average (ARIMA) model to generate the full probabilistic forecasts beyond the horizon. In this proposed method, the underlying RP is extrapolated first, and then the extended timeseries are generated simultaneously by sampling from the new RP. To validate the accuracy of the extrapolated data in the short-term, part of the timeseries with longer histories are excluded from the training process and only used for testing.
The sparse FPCA was applied to analyze monthly gas production data from 200 multi-fractured horizontal wells (MFHWs) of a selected operator in the Montney Formation in Canada. The results indicate that the production data of all the wells could be easily condensed using only two principal components, describing more than 99% of the information content of the production timeseries. Additionally, the resulting decomposed components were convoluted, and the production profiles of the wells with short histories were extended from the information contents of the ensemble. Additionally, with the proposed stochastic ARIMA technique, the production profiles of all the wells were forecasted for 400 months beyond the ensemble limit. The results demonstrate that the extrapolation could accurately match the measured data used for testing, which provides confidence in the stochastic long-term forecast.
This study demonstrates for the first time that sparse FPCA can be combined with the ARIMA model to quickly conduct the probabilistic production forecast for hundreds and even thousands of MFHWs simultaneously, which can significantly improve the current type-well modeling workflows.
Digital Solution for Coiled Tubing Pipe Pull Test Automation and Placement Optimization
Authors: Fonseca S. Hassig , Armstrong B. , Fossati L. , Brouwer W. 
Published: March 2024

Abstract
A new coiled tubing (CT) pipe pull test placement optimizer and automation solution is developed and integrated into an autonomous CT unit. This method provides consistency in strategic and automated pull test placement to extend the life of the pipe and consequently reduce total cost of ownership and greenhouse (GHG) emissions. A case study in the North Sea showcases the solution in real-time operations and simulated cases demonstrate the potential impact.
Pull tests are a common means of mitigating stuck pipe in CT operations. Traditionally, they are executed at fixed intervals while the CT is run in hole. Risks associated with this rote approach include repeated pull tests at an already fatigued section, which accelerates fatigue of the CT pipe, and pull tests executed in wellbore sections with completion restrictions. The new solution addresses those risks by systematically combining the pipe's fatigue profile, weld points, and completion information to strategically adjust the pull test schedule, reducing the impact of those tests on pipe fatigue and the risks associated with drifting across downhole completion jewelry.
The pull test automation and optimization are integrated into an automation-enabled CT unit in the North Sea. The automation eliminates the human factor and the risk of repeating pull tests at the same locations on each run; it also minimizes pull tests at the weakest points, which include the weld points where cycle fatigue is accelerated, and it eliminates pull tests at restrictions, reducing the risk of abrading or damaging completion jewelry. Finally, besides standardizing pull test placement, the combination of the pull test optimization and automation frees the CT operator to focus on other critical elements of the operation such as running and monitoring the unit and downhole tools, managing the crew, and engaging the customer representative.
The performance of the pull test automation and optimization solution is tested in a simulated environment to quantify the impact on the CT pipe from new (0% fatigue) to end of life (EOL, 100% fatigue). The simulation uses a CT pipe with 1 3/4-in. outer diameter (OD) and a mission profile from a previous intervention campaign. CT of this OD is common in CT operations worldwide, making it an interesting test subject for the analysis. As compared to the traditional pull test approach, the optimized pull test placement redistributes the fatigue to less-fatigued sections of the pipe and extends the useful life of the pipe from 137 runs to EOL to 176 runs to EOL. Extending the useful life by 28% is equivalent to reducing the pipe's run-on-run cost and GHG manufacturing emission contributions by 22%.
Successful Intervention in U and W Shaped Wells in Eagleford Basin – A Case History
Authors: Unnikrishnan Vikram , Navin Guruswami 
Published: March 2024

Abstract
An operator in Eagleford basin, decided to optimize production, by minimizing drilling efforts. This led to two wells drilled in a distinctive "U" and "W" shape, which would result in equivalent treatable laterals lengths in a lease with tight boundaries.
Plug and Perf stimulation technique was carried out in these two wells and post stimulation cleanout had to be performed. Intervention in these unique shaped wells need to be planned with the proper Bottomhole Assembly (BHA) configurations to ensure that that no misrun occurs. Though these wells are drilled successfully with the rig, since there is rotational and axial capabilities, it does not necessarily mean that a Coiled Tubing (CT) intervention would be less challenging. The frac plugs for isolation were set not just in the straight sections of the well but also in some part of the bend as well.
This paper will highlight the operational planning that was involved prior to performing intervention in these two wells. A complete coiled tubing modelling along with bending analysis on the milling BHA was performed to ensure that the downhole assembly does not undergo any failures due to well profile.
A total of 32 frac plugs in "W" shaped well and 38 frac plugs in "U" shaped well were successfully cleaned/milled out. The two wells were completed with 5 ½", 23 lb/ft casing with a Measured Depth (MD) of 17,846 ft and 21,064 ft respectively. A 4 ½" Tricone bit along with a 3 1/8" workover motor and extended reach tool was utilized for the operation.
Due to the pre-planning performed during the BHA selection, it eliminated a second run in each well, thereby allowing the operator to save around $150,000 on intervention costs. This paper will act as a guideline for any future intervention planned in wells with unique geometry.
Unique Electric Line Deployed Mechanical Cutting, Milling and Pulling Solution Successfully Applied in a Complex Fishing Operation, Regaining Access to a Critical Well
Authors: Murchie Stuart William , Magnussen Odd Einar , Finnesand Tore , Andersen Kristian , Gaballa Peter 
Published: March 2024

Abstract
An offshore injection well in an operating field situated in the Norwegian Continental Shelf was being used for secure dumping of old drill water and well debris, this being a critical resource in support of field operations. During a routine check of the functionality of the well's downhole safety valve (DHSV) it failed its seal test. A flow tube exercise tool was run to try and resolve the situation, however it proceeded to get stuck within the DHSV, preventing the valve functionality, blocking access to the well and hence rendering the well unusable until a solution was found.
The customer utilised all usual means to fish the exercise tool, with numerous slickline and e-line runs to jar and pull the fish proving unsuccessful. An assortment of high strength fishing tools were also used, including a high strength stroker providing as high as 100 Klbs force. This too was unsuccessful, proving brute force was not the solution. A detailed analysis of the situation was carried out to determine the probable cause, the extent of the challenges faced, and the appropriate solution options available. A thorough recovery plan was then devised based on a number of key steps and processes to be executed, with a decision tree created to aid operational progress. Steps included a means of determining the exact position of the core of the exercise tool. Bespoke tooling was also designed and tested to provide the securing, cutting and milling of several internal components of the exercise tool to enable it to be pulled free from the valve.
These e-line deployed solutions were highly innovative, providing extremely effective, precise, and controlled capabilities resulting in the flow tube exercise tool retrieval, in turn enabling further intervention operations and a subsequent re-completion to be carried out. As a result of the processes and solutions devised to recover the stuck exercise tool from this well, a new method for securely exercising DHSV flow tubes using strokers has been devised and applied as an alternate method by the operator.
Development and Initial Trials of Thermally Processed 95-Ksi Coiled Tubing
Authors: Elliott K. , Molero N. , Srinivasan H. , Arriaga E. , Al Qatari F. , Alsheheri M. 
Published: March 2024

Abstract
With a significant number of exploration and production programs pushing intervention boundaries, 95-ksi grade quenched and tempered (Q&T) coiled tubing (CT) has begun to be utilized in high-profile sour environments. This paper details the development of the newest 95-ksi grade of (Q&T) CT, specifically designed for increased fatigue life of existing products with performance in sour environments.
The authorship team is comprised of a multidisciplinary group within the CT business, including manufacturers, service companies, and the operator. Each stakeholder has different expectations regarding this development, but the main outputs of the program need to be (1) a repeatably manufacturable grade with (2) improved fatigue life and (3) resistance to catastrophic failure due to exposure to sour environments. This study describes the design control process that accounts for the concerns of all stakeholders.
The present review covers the initial development activity of identifying an alloy to make 95-ksi grade tubing. The process examined improvements to low cycle fatigue life and sour performance over 90-grade non-Q&T CT. Laboratory test results of 95-grade Q&T tubing are presented in this work. The low cycle fatigue testing comprises tests both with and without sour exposure. The testing without sour exposure is useful for providing comparative information to show how this grade can have an increased service life compared to 90-grade conventionally produced CT. The testing with sour exposure can be compared to the testing without exposure to show that low cycle fatigue life can be successfully modeled despite even in sour environments. The testing presents an examination of bias welds testing in low cycle fatigue as bias welds are considered a sensitive location for CT failure.
In the present decade, CT intervention requirements combining deeper extended reach horizontal sections and high-pressure cycling in sour environments are becoming more frequent, driving operators, service companies, and manufacturers to jointly pursue technologies and engineered solutions for safe and effective CT work. The study presented here paves the road for implementation of a value Q&T offering for such challenging environment.
Compression-Tolerant Mechanical Tubing Cutter with High Expansion Ratio and Real-Time Surface Readout
Authors: Cygan A. Z. , Osmond T. M. , Billingham M. E. 
Published: March 2024

Abstract
Mechanical pipe cutters are an increasingly attractive option for intervention and plug and abandonment (P&A) campaigns due to their simplicity, ease of deployment, and reduced risk of stored energy inherent in traditional energized pipe cutters. Limitations of current mechanical cutter designs include small expansion ratios, challenges to cut pipe under compressive load, and limited surface readouts that require expertise to interpret. A mechanical tubing cutter has been developed that seeks to address these challenges and limitations.
The robust mechanical design in the new cutter features a high expansion ratio with the ability to cut in tension, neutral weight, or compression, including multiple cuts per descent. Critical surface readouts have been incorporated to provide a fuller understanding of the cut and well response. Fully automated cutting algorithms, which minimize user interaction, have been programmed into the service to provide an active, torque-controlled cut that optimizes penetration and delivers consistency in performance. The cutter is designed as a modular addition to a full intervention solution family to offer combinable, multiobjective descents with a light wellsite footprint.
This new cutter has been deployed successfully by several operators to enhance well production and to successfully execute P&A scopes where other solutions were unfavorable or financially untenable. Two case studies illustrate the application of features such as the downhole sensors, automated algorithms, and expansion ratio and show how these features are central to achieving a successful cut.
This tubing cutter design expands the utility of mechanical cutters to target pipe that was previously inaccessible due to restrictions or unforeseen tubing deformation. In addition, the cutter reduces the risk of cutting complications stemming from compressive and torsional forces acting on downhole targets. Downhole automation enhances cutting reliability through reactive torque control, programmed stall recovery, and real-time response to changes in cutting conditions.
Autonomous Restriction Navigation Through Wellbore in Wireline and Slickline Operations
Authors: DiPasquale S. , Meirkhan J. 
Published: March 2024

Abstract
A novel technique of autonomous restriction navigation that significantly increases efficiency and safety is presented. New algorithms orchestrate the automated winch control system to prevent over-speeding when passing through restrictions, which diminishes incidents of unintentional pull-off and toolstring damage caused by entering wellbore obstructions at high speed. Every pull-off incident would significantly reduce the production of the well because the toolstring and cable must be recovered. This new dynamic speed scheduling system optimizes restriction navigation, showing an order of magnitude improvement over industry-standard human-driven winch operation.
A new forward-looking algorithm analyzes restrictions in the direction of conveyance to predict the time and distance to future encounters with restrictions. It uses toolstring length, current depth, cable speed, and the winch controller's deceleration rate to maintain the maximum allowed speed until the exact moment deceleration must occur for the toolstring to enter a restriction at the proper speed. Finally, it maintains a higher winch gear even at low speeds when passing through restrictions except in those situations when extra-low speed is required.
The new technique has been extensively tested in intervention campaigns in the North Sea, allowing comparison against manual operation and previous-generation automated conveyance. Winch operators would often fail to slow down at restrictions or would slow down too early or too late. Previous-generation automation, due to its lack of forward-looking algorithms, would not decelerate until the toolstring encountered the restriction and could accelerate with the toolstring still in the restriction. To prevent this, the wellsite supervisor would need to spend extra time manually calculating top and bottom restriction depths for each conveyance direction, often leading to overestimation or miscalculation of the restriction declarations. In case studies from field trials, the new technique consistently uses the correct restriction speed for the entire toolstring length. Users only need to declare wellbore speed restrictions as they appear on the well diagram. In manual operation, an experienced user will retain high winch gear through a restriction, whereas previous automation would stop and change gear. The new technique digitalizes winch driving competency by incorporating high-gear retention. After a year of field trials with zero incidents, several case studies with multiple restrictions in the well confirm the greater efficiency of the new navigation technique over previous generations.
The developed comprehensive automated speed-control logic and restriction navigation technique maximizes conveyance speed while eliminating risk and costly errors. Its intrinsic value increases when operations are performed in highly sophisticated well completions and tortuous wells, which are becoming more common.
Improving Well Completion Efficiency Though the Implementation of Jointed Pipe Injector Technology
Authors: Richard A. , Miller H. , Herrmann J. 
Published: March 2024

Objectives/Scope
Currently, jointed pipe completions on live wells are performed by either a workover rig with a rig assist snubbing jack or a stand-alone snubbing jack. These technologies require extensive training and operator input to convey tubing in and out of the wellbore. Conventional snubbing jacks run the risk of losing control of the string when they are transferring load between travelling and stationary slips. The main objective of the Jointed Pipe Injector Technology is to provide a safer alternative by reducing operator input and reducing the risk of losing control of the string while reducing the time it takes to move tubular strings in and out of the wellbore under pressure.

Methods, Procedures, Process
Applying a jointed pipe injector into the well completions package where a typical jack would function removes the transfer of load because it maintains constant grip on the tubing, much like a coiled tubing injector. By integrating additional sensors into this package make-up and break-out procedures may be carried out remotely, further reducing operator intervention for remedial operations.

Results, Observations, Conclusions
Through the recent deployment of a rig-assist jointed pipe injector in the DJ Basin, the oilfield service companies have been able to reduce operator training time from months to weeks. Operator input has been reduced by over 94% compared to a conventional rig assist snubbing unit. Tubulars can be tripped in or out of the well at twice the speed of the conventional rig assist jack. The main injector control has been located remotely, reducing the number of personnel at risk on the work floor by 33%.

Novel/Additive Information
The deployment of the jointed pipe injector in well completion applications leads to levels of automation, control, and mechanization typically seen in modern drilling packages.