bluuebunny/crossref_metadata_2025_split huggingface dataset:
Factors Influencing the Precision of Swab and Surge Predictions During Tripping Operations
Authors: Cayeux E. , Ambrus A. , Dvergsnes E. , Johansen M. Dahle , Balov M. 
Published: February 2024

Abstract
Tripping operations are the source of possible serious drilling incidents caused by swab and surge pressures exceeding the geo-pressure margins. Yet, it is difficult to monitor the actual downhole pressure during tripping because of telemetry limitations but also because there are no available methods to measure downhole pressure below the bit. Hydraulic models are therefore necessary to estimate the downhole pressure along the whole open hole section, also below the bit. It is therefore important to understand the factors influencing downhole pressure estimations when the drill-string is only subject to axial displacement.
In most cases tripping procedures consist in a series of drill-string movements intertwined with connection procedures. While tripping, the drill-string needs to accelerate from a stand-still position and to stop at another position. As a result of these accelerations and decelerations, hydraulic calculations must be transient. Furthermore, the movement of the bottom of the string is not synchronous with the top of string displacement because of the elasticity of the string, meaning that transient torque and drag estimations are also necessary. Actually, when using a floater, the top of string movement is influenced by heave also during connection. When the drill-string is displaced, drilling fluid needs to be added or is returned to the trip tank, depending on the direction. Consequently, the drilling fluid columns in the string and in the annulus change position affecting the downhole temperature conditions. As the fluid density and viscous behavior depends much on the local condition of pressure and temperature, heat transfer estimations also play a role on downhole pressure estimations. The evaluation of downhole pressure requires the combined estimations of transient hydraulic, mechanical and heat transfer models.
The drilling fluid is also subject to gelling in a non-uniform manner along the borehole. Drilling fluid with high viscosity at low shear rate may take several minutes to return to hydrostatic conditions like for example during connection. Depending on the static and kinetic friction factors, part of the drill-string may remain stretched also after the top of string movement has stopped. Consequently, connection time influences the swab and surge variations for the next stand. Therefore, a tripping operation is typically a non-holonomic process which requires a continuous follow-up of the time evolution of the hydraulic, mechanical and heat transfer variables to be able to predict accurately the downhole pressure.
Through several examples from actual tripping operations, the importance of the mutual interaction between transient hydraulic, mechanic and heat transfer, as well as the non-holonomy of tripping operations is shown. Understanding the factors that influence swab and surge estimations is of paramount importance to progress with the automation of tripping operations.
Replacing Portland Cement with Granite-Based Geopolymers for Oil Well Applications; Conventional Two-Part System
Authors: Anya A. , Khalifeh M. , Kamali M. , Haddad Y. , Joppe L. C. 
Published: February 2024

Abstract
Inorganic geopolymers typically consist of aluminosilicate-rich powders and alkali silicate solutions as hardeners. When these components are mixed, geopolymers exhibit a behavior similar to that of cement. The final product leaves a significantly lower carbon footprint compared to conventional cement. This paper offers a comprehensive characterization of a granite-based geopolymer designed for oilfield applications, adhering to the standard tests specified by API RP 10B-2. It also highlights the advantages and current limitations of this innovative technology while identifying areas for further research and development.
This geopolymer has been specifically engineered to completely replace Ordinary Portland Cement in well cementing applications. We conducted a series of tests, following API standards, to evaluate its fluid-state properties, including viscosity, static gel strength, thickening time, static fluid-loss, free fluid, and density. Additionally, we examined its mechanical properties after solidification, such as sonic strength development, uniaxial compressive strength, and volume change. Our analysis of the granite-based geopolymer demonstrates the effective performance of the dispersant, reducing viscosity, and enhancing mixability. We observed a brief gel transition time upon setting, and the mix exhibited slight expansion during the strength development phase. Notably, strength development remained continuous and did not plateau even after 30 days of curing. These geopolymers combine high compressive strength with exceptional flexibility. Furthermore, temperature sensitivity analysis revealed that an 8ºC increase did not affect the gelation time.
This granite-based geopolymer is a cement-free system with a low calcium content, measuring less than 15% by weight. It presents a sustainable and environmentally friendly alternative for replacing Portland cement in oil wells, both during well construction and abandonment. Moreover, it proves to be an excellent choice for constructing CCUS (Carbon Capture, Utilization, and Storage) and geothermal wells.
Thermal Stimulation of Annular Shale Barriers for Long-Term Well Integrity
Authors: van Oort E. , Lucas A. , Kverneland J. , Godøy R. , Reitan H. , Aldin M. , Thombare A. 
Published: February 2024

Abstract
Annular shale creep barriers which can guarantee long-term well integrity over the entire lifespan of the well can be stimulated by temperature elevation caused by artificial heating inside the wellbore. Prior work has shown that heating can significantly accelerate barrier formation, but may also damage the shale formation if certain temperatures are applied. This paper reports on the optimum thermal conditions for shale barrier formation based on extensive new laboratory as well as literature data.
Thermally accelerated creep behavior was studied for the Lark and the Shetland North Sea shales. Large-scale triaxial equipment was used to study the behavior of shales under downhole stress and pressure conditions while varying temperature. In addition, an extensive literature study investigated the thermal effect of shales used for nuclear containment, such as the Boom Clay in Belgium, Cox Shale in France, and Opalinus Clay in Switzerland. The investigation focused on the impacts of temperature elevation on important shale properties such as creep rate, sealing and self-healing ability, and temperature-induced porosity, permeability, and mineralogical changes.
Both the laboratory investigation and the literature study showed that there is an optimum range for artificial thermal stimulation of shale barriers, with an upper temperature of 200°C – 300°C that should not be exceeded. At lower temperatures, thermal pore fluid expansion may lead to effective stress reduction and shear failure on shale bedding planes. In the optimum range, fluid thermal expansion is effectively negated by thermally-induced shale consolidation, and barrier formation is optimally accelerated, which is of great practical value for field implementations. Above the optimum range, irreversible dehydration and metamorphosis of the clay constituent of the shale happen and the shale loses its ability to creep to form a barrier and self-heal. This important result shows that heating inside wellbores to improve/accelerate creep of shales needs to be a controlled, engineered process in order to yield a competent barrier. This favors the use of a temperature-controlled heater rather than a less-controllable exothermic reaction.
Shale barriers seal annuli much better and more reliably than cement barriers. Moreover, their self-healing ability offers the ability to guarantee annular well integrity for an indefinite period, including the P&A phase. Thermal stimulation is preferred by operators to accelerate barrier formation without requiring annular access. The findings of this paper provide important theoretical and practical guidance on how to optimally stimulate shale barriers and avoid pitfalls associated with thermally-induced shale damage.
Development and Validation of a Rotating Wheel Coriolis Mass Flowmeter for Accurate Measurement of Drilling Fluid with No Pressure Loss
Authors: Cayeux E. , Holsaeter A. , Leulseged A. , Moi S. , Gravdal J. E. 
Published: February 2024

Abstract
Accurate measurement of the flow rate out of a well during drilling is essential for optimizing drilling performance and ensuring operational efficiency and safety. In conventional drilling, a flowmeter placed in the return flowline shall not introduce pressure drops and shall work without being filled. A new concept using a rotating measuring wheel fulfills these two requirements. However, it needs to be verified that the concept is sufficiently precise over the wide range of flowrates that can be experienced during a drilling operation as well as being accurate for non-Newtonian fluids containing cuttings and gas.
The measurement principle of the rotating wheel mass flowmeter involves directing the fluid, including cuttings and gas, through the center of a horizontal rotating wheel and collecting it via a funnel. The measuring wheel has vertical vanes onto which the drilling fluid applies a force due to the Coriolis acceleration. The forces on the vanes result in a torque that can be measured on the axle of the driving motor. This torque is directly proportional to the mass flowrate of fluid passing through the measuring wheel. To verify the accuracy of the sensor, a medium scale apparatus has been built and used in a flow-loop together with a high precision vibrating tube Coriolis flowmeter for reference. The test procedures consist of measuring flowrates with a range scale of 5 to 120 kilograms per minute with various drilling fluids.
The medium scale apparatus successfully handled flow rates up to the expected operational limit with optimal rotational speeds identified for different flow rates. The experiments encompassed various fluids, including water, glycerin (representing high-viscosity Newtonian fluid), and non-Newtonian drilling fluid samples. During the tests, issues related to design, instrumentation, and control system were identified and addressed. The results of the tests confirm that the rotating wheel mass flowmeter establishes a linear relationship between torque and mass flow rate, and that this linear relationship is valid both at low and high rotational speeds.
The benefits of this new mass flowmeter include acceptable accuracy and reduced maintenance requirements, and is also functional at very small rates, compared to traditional methods like the flow paddle. This research represents a significant step towards the development of a full-scale device, supporting an agile development process in the field of digitalization and automation of drilling operations.
Active Magnetic Ranging While Drilling: Tool Function and Tests Results
Authors: Husby K. , Hjelstuen M. , Eriksen T. J. , Liberale A. , Koraei M. , Ytrehus J. D. , Saasen A. 
Published: February 2024

Abstract
A well intercept operation has the scope to drill into an existing well. Similarly, some infill drilling operations are conducted with the scope of avoiding interception with other wells. A prototype of a tool for Active Magnetic Ranging While Drilling (AMR) without the use of a separate wireline operation has been developed. The main scope of the current article is presenting the results of a series of prototype tests of this tool in test wells.
The ranging tool emits a low frequency alternating current into the formation to reach the target well, and then run through that well's casings and back to the well being drilled. This electric current set up a variable magnetic field that is measured by the AMR tool determining the direction towards the target well as well as the distance.
In case of drilling a relief well, 10 - 25 wireline runs are needed before the target well is intercepted. The present AMR tool is fully integrated in the drill pipe and, thus, no wireline operations are required, and all the tripping operations are avoided.
A prototype of an active magnetic ranging tool on the drill pipe has been developed. This tool is outlined in the paper. Most focus will be given to a performance test conducted in a research well in Norway. Different pipes with controlled earthing are placed in neighbour wells to the well with the logging tool. The AMR tool was run in one of the research wells and the direction and distances to other target wells were measured. The set-up and the results of this logging operation that was conducted on the drill pipe is described in detail. It is described how the direction and distance between the two wells are measured using the tool.
Evaluating Profitability of Hybrid Approach for Early Stuck-Sign Detection: Analyzing False Alarms and Quantifying Reduction in Nonproductive Time
Authors: Kaneko T. , Inoue T. , Nakagawa Y. , Wada R. , Abe S. , Yasutake G. , Fujita K. 
Published: February 2024

Abstract
This study investigates the profitability of early sign detection of stuck pipes by considering the trade-off between reducing nonproductive time (NPT) through detection and increasing NPT through false alarms. Our objectives are to propose a hybrid approach combining physics-based knowledge and data science, analyze the timing of false alarms, improve the model to minimize false alarms, and evaluate profitability by quantifying NPT reduction.
Our proposed detection method combines physics-based knowledge and data science techniques, specifically capturing torque and standpipe pressure increases. First, we enhance the method by refining the model equation, learning method, and anomaly calculation method. Second, using field data from multiple wells collected over several months, we analyze the timing of false alarms and further refine the model to reduce them. Finally, to evaluate the profitability of our method, we examine the frequency of stuck incidents, NPT owing to stuck incidents, and NPT owing to false positives, and then quantify the reduction in NPT, considering both true-positive and false-positive rates.
By applying our method to 11 wells, we generated approximately 130 days of stuck risk output. By determining a threshold that detects 40% of the stuck signs, we identified 37 false alarms. Analysis of these false positives revealed that nine could potentially indicate stuck signs, 23 could be disregarded by the operator or filtered out through data preprocessing, and five persist as challenging cases for the current method. Based on these findings, we further enhanced the model to reduce false alarms and successfully reduced the count to 11. In addition, our profitability calculation, based on NPT and considering the trade-off between true positives and false positives, demonstrates the potential for a reduction of several hours per year. Furthermore, implementing stuck sign detection is expected to lead to cost savings associated with bottom hole assembly losses, fishing, and sidetrack operations.
The novelty of our research lies in evaluating the profitability of early stuck sign detection by analyzing false alarms using multiple wells and long-term data. This analysis enables us to enhance the detection model and demonstrate the profitability of the proposed hybrid approach. Our study emphasizes the importance of considering both the true-positive and false-positive rates to enhance and evaluate the performance of early stuck sign detection methods.
Applications of Large Language Models in Well Construction Planning and Real-Time Operation
Authors: Yi Michael , Ceglinski Kamil , Ashok Pradeepkumar , Behounek Michael , White Spencer , Peroyea Trey , Thetford Taylor 
Published: February 2024

Abstract
In today's well construction operations, a substantial volume of data is generated and stored across multiple databases. The primary objective being to use them as a guide for future well construction optimization. However, much of this data gets lost in computer storage, and appropriate information is difficult to find at the right time. This paper shows the results of deploying a generative pre-trained transformer (GPT) large language model on an operator's dataset to alleviate this problem.
The process starts with gathering all relevant data into a common database. In this case, the dataset included sensor data, processed data, morning reports, end of well reports, after-action reviews of non-productive times, bit forensics data and publicly available data from wells drilled by other operators. The files were pre-processed, and metadata was added appropriately to ensure appropriate indexing and training of the information. This data is then fed to the cloud platform on which the model is learnt. The model is then integrated into the data platform so that the end users can pose queries.
The dataset consisted of more than 200 wells of the operator in a region that the operator is actively drilling. Data curation was a time-consuming task that had to be performed to ensure only quality and organized information was fed to the model. Documents containing well construction related subject matter were also used in the training to provide the end user assistance with core concepts. During the test stage, a multitude of questions were posed to the platform, including questions such as: What happened the last time there was a stuck pipe in this region? What is the best ROP that could be attained in the lateral section? Significant time savings were recorded due to the ease with which information could be retrieved. A big concern was the potential for wrongs answers being provided to the questions. To alleviate this concern, all answers were accompanied by references found in the database, to give the person reviewing the answers confidence in the answers.
This paper introduces the benefits that large language models (LLMs) bring to both well planning and real-time operations. LLM offers the capability to be able to retrieve information extremely quickly and provide answers in a conversational format to user questions. This paper also provides recommendations to the industry and details some of the challenges to adopting LLMs.
Thermally Activated Lost Circulation Mitigation of Severe Losses in Fractured and Vugular Formations
Authors: Denduluri V. , Thombare A. , Aldin M. , Juenger M. , van Oort E. 
Published: February 2024

Abstract
Severe lost circulation occurs frequently in fractured and vugular media. When drilling fluid enters vugs or fractures, it experiences a temperature increase due to the reduced influence cooling from the wellbore and the growing influence of the higher in-situ formation temperature with invasion depth. This temperature increase can be exploited to help plug the vugs or fractures. If the lost fluid contains Thermally Activated Lost Circulation Materials (TALCMs), it experiences a strong temperature-induced increase in viscosity, making it effectively unpumpable and non-displaceable, thereby stopping further fluid losses. TALCMs can be employed as additives in drilling fluids, in dedicated treatment pills, or mixed with cement for dedicated squeezes.
TALCMs are a new type of temperature-tunable material that can be engineered to mitigate severe losses in a variety of geological formations with varying temperature gradients and depths. By exploiting the formation’s own temperature gradient, effective fracture or vugular sealing can be obtained, which opens up an entirely new way to mitigate severe losses in oil, gas, and geothermal wells, where lost circulation is a prime source of non-productive time.
Facilitating Directional Drilling Work to Reach the Target Entry by Calculating a Safe Operating Envelope
Authors: Saavedra Jerez L. , Cayeux E. , Sui D. 
Published: February 2024

Abstract
Nowadays, complex 3D trajectories are handled with a succession of circular arcs. Although they have constant curvature, their toolface is not constant. Consequently, directional drillers must adjust the toolface regularly to reach the target entry within its tolerances. This paper investigates the use of the constant curvature and constant toolface curve (CTC in short) as an alternative to the circular arc to facilitate the directional drilling work to reach the target entry within its boundaries.
The problem is addressed by calculating a safe operating envelope (SOE) to reach the boundaries of the target entry. The target entry tolerance is discretized as a polygon. From the current bit position and its direction, the possible choices of curvatures and toolfaces are obtained in order to reach the edges of the target entry shape. The SOE can be calculated with the circular arc or with the CTC curve. It is, therefore, possible to compare the advantages and disadvantages of both types of curves to attain the target entry and stay within its boundaries.
The circular arc is shorter than the CTC curve. However, it requires adjusting the toolface during the navigation, which is not the case with the CTC curve. As a result, the directional driller can easily control the bottom hole assembly (BHA) direction such that the well lands within the target entry limits by using set-points for toolface and curvature inside the calculated SOE. Furthermore, a new way to represent the SOE is introduced. It makes use of a 3D cylindrical representation where the curvature is mapped as the height of a cylinder, while the toolface corresponds to the azimuth in the cylindrical coordinate system, and the length is linked to the radial distance. This provides a visual aid to understand the SOE. Moreover, this visualization helps to appreciate the relationship of the initial bit location and direction in the construction of the SOE and how the margins increase in a particular manner as the bit approaches the target entry polygon.
The CTC curve is the natural one followed by directional positive displacement motors (PDM) or rotary steerable systems (RSS). Potentially, the CTC curve may be a door-opening solution to automated directional drilling control as it is easier to be followed by both PDM and RSS.