bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Automated Pore Pressure and Wellbore Stability Updates in a Digital Twin, Using Smart Agents and Log Predictions Ahead of Bit, Example from Norwegian Continental Shelf
Authors: Lothe A. E. , Roli O. -A. , Skogestad J. O. , Cerasi P. , Boukili M. , Kristiansen T. G. , Grøver A. , Wølstad-Knudsen S. 
Published: February 2024

Abstract
The main objective in this work was to develop and test automated pore pressure and wellbore stability predictions ahead of bit using a digital twin. The new automated real-time workflow, with three smart agents for pore pressure, mudweight and well pressure was tested on historical data and real-time drilling campaigns for one exploration well and several production wells in the North Sea and offshore Mid-Norway. A digital workflow is set up from pre-drill 3D basin scale pore pressure modelling using a stochastic Monte-Carlo approach, including an automated update of pressure prognosis while drilling using sonic or resistivity data. Additionally, the innovative approach will also reduce the uncertainty in the predicted mud-weight window ahead of the bit. Three new smart agents have been implemented in a real-time data platform for drilling; one for pore pressure prediction, one for mudweight real-time calculations and one for well pressure real-time predictions.
The new automated workflow has been tested on several wells, either in real-time, or on historical data as playback. Both pressure real-time updates using sonic log (for exploration well) and resistivity data (for production well) have been tested with very good results, especially when filters on the raw log data are used, removing artefacts in input data, effect of well inclinations, lithologies etc. In addition, the real-time Equivalent Circulating Density (ECD) prediction has been compared with downhole ECD measurements. Digital twin using playback data from a well, offshore Mid-Norway has been carried out with automated correction and smoothing of the calculated pore pressure from resistivity log. The new automated workflow will contribute to increase the efficiency of drilling operations subject to narrow pressure margins and uncertain reservoir pressure, by providing a quantitative and adaptive automated workflow to support the drillers/rig crews.
The new automated workflow is presented for both exploration and production wells and the workflow can contribute to more cost effective and safer operations. The methodology can in the future be combined with machine learning.
Experimental Visualization of the Effect of Flow Rate on Downhole Drilling Vibration
Authors: Maitra E. K. , Al Dushaishi M. F. 
Published: February 2024

Abstract
Downhole drilling dynamic data has proven to be valuable operational information for vibration mitigation and drilling optimization. Yet, the downhole dynamic behavior of the BHA is often misinterpreted. Most downscaled experimental investigations neglect the changes in dynamic field conditions due to fluid flow. The objective of this work is to establish a visual understanding of downhole vibration data analysis in the presence of fully circulated fluid flow and to investigate the effect of flow rate on the BHA lateral trajectory, using a scaled laboratory BHA. A mechanically downscaled test assembly adhering to the geometric and material property relations of a field-size BHA section was designed and manufactured to investigate the nature of lateral vibration under field-like fluid flow conditions. Axial excitation and rotation were induced respectively using an electromagnetic shaker and an electrical motor. Fluid was pumped through the BHA using an electric pump and an in-house designed swivel. The BHA trajectory was mapped using inductive displacement sensors mounted outside the transparent wellbore structure for direct visual correlation between the BHA movement and the vibration data. Real-time induced bit vibration was observed and recorded using a high-frequency tri-axial accelerometer. The results from this experiment provide precise and insightful visual information for BHA trajectory correlation with the acceleration data acquired under field-like fluid flow conditions. The BHA vibration behavior of high-frequency accelerations (shock and vibration), critical lateral vibration phenomena such as whirling, and shift in dominant vibration frequencies were characterized based on both the nature of dynamic forces at the bit and fluid flow rates. Instead of a general observation of the vibration-damping effect in the presence of circulating fluid, the experiment also presents correlations between vibration characteristic changes at different frequencies for different flow rates. In conclusion, the investigation distinguishes between the dynamic relation of fluid damping of vibration and fluid-induced vibrations, both in relation to the dynamic vibration data and the downhole dynamic behavior of BHA movement. The novel experiment establishes both quantitative and qualitative relations between the observation of acceleration data and physical vibration behavior during drilling in the presence of circulating fluid. The experimental results provide clear insight not only into the dynamic nature of vibration-damping but also into fluid-induced vibrations, which affect the window of safe operating drilling conditions.
An Analysis of Drilling Projection Uncertainty and Implications for Collision Avoidance Management Systems
Authors: Willerth M. , McGregor A. 
Published: February 2024

Abstract
During well planning, specifying the separation that must be maintained from offset wellbores is critical to ensuring safe operations. Recent efforts on API RP 78, an upcoming recommended practice for wellbore placement, have provided guidelines for calculating safe separation distances and engineering considerations for those calculations. A major milestone was the publication of a separation rule (Sawaryn, et al. 2019) standardizing a formula for separation factor (SF), which in turn defines the minimum allowable separation distance (MASD) between two wellbores and the allowable deviation from plan (ADP) for a wellbore being drilled. One element of this formula, σpa, describes the accuracy with which a future wellpath can be predicted. Prior guidance provides a suggested value for σpa (1.6ft or 0.5m at 1-sigma) based on heuristics. A more rigorous approach for estimating this value is presented, where the design of the drilling program can be considered.
A framework is proposed for modeling deviation from a projected path using a planned trajectory, bottom hole assembly (BHA) properties, and survey practices. The method identifies where a deviation is detected through survey measurements and estimates a planned recovery operation. Equations are provided for estimating the distance from plan at deviation detection along with the maximum expected deviation during recovery. Common drilling scenarios are analyzed for sensitivity to operational parameters such as survey course length, sensor offset, toolface control, and BHA performance. The impact of varying σpa is explored across prototypical collision avoidance cases. A discussion of the relationships between the σpa value and the common collision avoidance calculations such as SF, MASD, and ADP is included along with considerations for the design of a risk management policy.
Survey course length, survey sensor offset and uncertainty in directional performance are all shown to have a significant impact on the potential maximum deviation from plan. An additional factor considered is the aggressiveness expected when performing recovery operations. An analysis of common drilling scenarios suggests the previously provided guidance of 1.6ft at 1-sigma appears suitable for cases where the directional behavior of the BHA is well characterized and the combination of course length and survey sensor offset is kept to 150ft or less. Longer survey course lengths, larger sensor offsets, or uncertainty in directional performance of the BHA can produce larger σpa values, in some scenarios causing a significant impact on the MASD and ADP.
Previous work has called attention to the uncertainty in drilling to a projection, but up to now there has not been a rigorous method for estimating that quantity. With the methods outlined in this paper well planners and drilling engineers can make more informed decisions on how to ensure safe separation practices in their own operations.
Interoperability for Drilling Process Automation
Authors: Kuilenburg R. Van , Isbell M. , Behounek M. , Macpherson J. , Schaefer S. , Fox T. , Pirovolou D. 
Published: February 2024

Abstract
Drilling automation and remote operations are driving advisory systems to provide a safe operating environment, protect the wellbore, and optimize efficiency at the wellsite. These interoperable systems deliver guidance to control systems, for example set points and limits for drilling parameters. The Drilling and Wells Interoperability Standard Industry Group (D-WIS) under the SPE Drilling Systems Automation Technical Section (DSATS) wants to accelerate interoperable system implementation by outlining a compelling value case.
The adoption of drilling operation automation systems is increasing operational efficiency and opening new opportunities to manage drilling with advisory systems. These systems are the focus of efforts in interoperability (i.e., plug-and-play functionality) to remove data communication obstacles and allow the implementation of the next generation of advisory and process control technology. This paper describes the technology focus, status, and impact of the current industry efforts and organizations contributing to interoperable systems regarding the core system components and standardization needs. The value case is made for an interoperability standard suitable for large scale industry deployment.
The current industry state reveals custom-made supplier solutions continuing to expand and evolve with limited applicability due to a bespoke approach. The authors observe and contrast this method with an interoperable system approach to make the value case in terms of easier and faster implementation and scalability, better reliability and access to data, and lower development and operations cost, resulting in a higher overall value. A comparison of the two competing scenarios along with past industry efforts toward standardization clarifies how to best realize the vision of safely and efficiently sharing information and facilitating drilling operations. Collaborative efforts between industry organizations also help address areas of overlap and gaps related to interoperability and creation of a standard. The conclusions outline the minimum requirements of a focused industry effort to deliver an implementation-ready system. System adoption is accelerated by creating deliverables fit for roadmaps and specific collaboration points.
The paper examines the effectiveness of current interoperable system efforts. It describes and demonstrates industry influencing work towards interoperable drilling systems and builds on a collection of industry work beyond Sadlier and Laing 2011, and Macpherson et al. 2013.
The Value of Process and Application Consistency in Drilling Automation
Authors: Auld S. , Whitlow Z. , Hopwood F. , Kern S. , Willerth M. 
Published: February 2024

Abstract
The drilling industry has undergone significant changes in recent years, leading to increased efficiency, lower costs, and reduced emissions per production unit. As unconventional well construction complexity continues to increase, the next wave of innovation lies in process automation, offering improved consistency and the opportunity to enhance drilling engineering designs.
Effectively automating drilling a stand while minimizing human variability requires a scalable control system, providing adaptability, seamless implementation, and improved operational outcomes. The system requires high- and low-level process control components to effectively control rig machinery within the bounds of the machine limit controls. By using automation sequences while engaging and disengaging the drill bit, operational states such as breakover, optimal weight on bit (WOB), steady state hookload, and zeroing become easier to distinguish.
Through consistent implementation of process automation in drilling operations, the impact on operational outcomes became evident. Analysis of bit disengagement in a series of automatically drilled stands in the lateral revealed a consistent breakover range of 18 to 22 ft. This is particularly noteworthy as breakover is typically more challenging to identify and prone to variability in manual operations.
Zeroing WOB in the lateral at a predetermined drilling interval is common practice to calibrate the drilling system, and procedures provided by the operator are often conservative due to human variability resulting in slower process execution. While drilling automated stands in a lateral, it was determined the lowering sequence of the process could be reduced by half to effectively zero the WOB and differential pressure, reducing invisible lost time.
Not all invisible lost time and variability is human related; variability due to equipment design was reduced. Torquing drillpipe connections is essential to drilling a well. Development of high spec automated floor wrenches improved make-up connection torque accuracy and consistency primarily associated with fundamental tool design. These improvements led to a connection integrity paradigm shift, reducing manual tong usage by 99%, effectively eliminating the need for high torque tongs at a wellsite, leading to improved tripping time and safety.
As drilling automation continues to evolve, the outcomes obtained through consistent process execution provide valuable insights. Additionally, this contributes to a decrease in emissions per unit of hydrocarbon production. Consistency through automation reveals new avenues for in-depth technical discussions on achieving safe and efficient drilling of progressively complex wells.
The Insulated Drill Pipe - Field Experience and Thermal Model Validation
Authors: Vetsak A. , Besoiu C. , Zatonski V. , Torre A. , Hodder M. , Toews M. 
Published: February 2024

Abstract
To drill deeper and hotter wells, such as for high temperature high pressure (HPHT) oil and gas or geothermal applications, proper management of bottomhole temperatures is critical to ensure survival of electronic tools and to improve drilling performance. The paper introduces a new type of the Insulated Drill Pipe (the "IDP") which minimizes heat transfer from the annulus into the drill pipe, to deliver drilling fluid to the bottomhole assembly (BHA) with substantially cooler circulating temperature than using the non-insulated drill pipe.
An iterative design process was followed to develop a robust and cost-effective insulating material that can be applied to the inside and outside of the standard non-insulated drill pipe. After testing a series of different insulating materials in the lab and in the field as prototypes, a new coating system was chosen for the first generation of the IDP. Concurrently, a detailed thermal model was developed to estimate the expected cooling effect of the IDP.
A full IDP string was manufactured in 2022 and was subsequently used in three field trials: a geothermal test well in New Mexico, the USA DOE FORGE project in Utah, and a US-based shale well. During field trials, mud inlet and outlet temperatures and measurement while drilling (MWD) temperatures were monitored. In some cases, mud chillers were used at the surface to decrease the inlet mud temperature. Both real-time and recorded MWD temperatures were obtained. At FORGE, recorded circulating temperatures at the MWD were reduced by up to 42 °C (75 °F), from 107 °C (225 °F) to 65 °C (150 °F) in formation temperatures exceeding 150 °C (300 °F). Analysis of wear and robustness of the insulating material were inspected on all joints of drill pipe and damage in vertical and deviated wells was minimal. High normal forces and friction in a horizontal well did result in significant damage to the coating which can be remedied through improved coating design. The thermal model was validated with the measured data and used to accurately predict the performance of IDP in future runs.
This is the first extended field trial of the IDP, and the results demonstrate the value of the IDP to reduce mud temperatures downhole. The IDP allows for improved cooling of the BHA components, particularly electronics, and extends the operating window of existing MWD, electronic equipment and other BHA tools to deeper and hotter environments. This is critical for the HPHT wells and for deep and hot geothermal wells, reducing the cost of the instrumented BHAs for these wells, while improving downhole tool reliability, and reducing a frequency of tripping operations due to downhole failures. The developed thermal model can also provide maximal connection times by estimating the rate of borehole heating while rig pumps are off.
To What Extent Can the Notion of an Effective Length Be Reliable to Assess the BHA Lateral Behavior?
Authors: Mahjoub M. , Dao N. -H. , Nguyen K. -L. , Menand S. 
Published: February 2024

Abstract
Many models in the industry use the notion of an effective length to make predictions about the bottom hole assembly (BHA), whether for its directional behavior or its lateral vibration tendency. A given criteria is chosen to cut the drill string at a certain distance from the bit and use only that part for the computations. In this paper, this cutting distance is referred to as the effective length. Though computationally efficient, and thus providing fast real-time predictions, there is no consensus on what criteria should be chosen, nor a "bulletproof recipe" on how to compute that length. Miscalculating this effective length, especially for vibration mitigation purposes, can lead to suboptimal rotation speed selection, potentially causing failure.
To address this challenge, different choices of effective length computations are compared in terms of BHA yield rate prediction (build/drop and turn rate). Past a given distance from the bit, the computed side force and tilt at the bit are nearly identical, meaning that any element very far from the bit is negligible in the static calculation. However, studying lateral vibrations is more complex especially at low inclinations or in horizontal wells with high weight on bit (WOB) where the drill string can move more freely with snaking and whirling motions. A nonlinear time-domain model is utilized to evaluate the propagation of lateral vibrations up the string. A sensitivity analysis was then conducted on several BHA types and lengths, considering different boundary conditions in vertical and horizontal wells.
Directional models are found to be reasonably unsensitive to the choice of the effective length because they are based on steady-state computations, but the same cannot be stated for dynamics. This study developed a more robust approach to estimate properly the effective length for lateral vibrations, an essential for BHA resonance. The theoretical predictions of critical speeds were compared to time-domain simulations, which take into account the nonlinearities related to contact and friction forces. Spectral analysis of the results helped identify the main sources of vibration, whether it comes from BHA mass imbalance, drill string-wellbore interactions, or other sources. This combination between frequency- and time-based analyses is used to validate our choice of the effective length.
Many models, from steady state to dynamics with both frequency and time domain analysis, are used to approach the effective length problem from various perspectives. This study aims to compensate the lack of in-depth analysis on this important subject. It shows the importance to understand the strengths and limits of frequency-based models compared to the more complex time-domain modeling.
Settled Barite as a Potential Barrier Material: A Field Case Study
Authors: N’gouamba E. , Bhuiyan H. , Stroisz A. M. , Taghipour A. , Skorpa R. 
Published: February 2024

Abstract
During plugging and abandonment (P&A), sedimented and compacted barite adds considerable complexity to the plugging operation. Casing cut and pull is alone responsible for approximately 50% of the cost to establish a formation-formation barrier. However, if the settled barite in the annulus can be used as an additional barrier element, P&A operations can be simplified, and the cost reduced. With this in mind, it is therefore necessary to investigate the sealing and mechanical properties of settled barite. In this study, settled barite from a field on the Norwegian Continental Shelf is investigated to understand the mechanical and sealing properties of the settled and compacted barite from the wellbore and to compare them with cement properties. Strength and ultrasonic measurements are carried out on cored samples to assess their mechanical properties. Computed Tomography scans give an overview of the sample’s texture, and the Scanning electron microscopy provides insight on the microstructure and changes in the chemical composition of the barite from the oil well. In addition, the cohesion (or resistance to mobilisation) of barite powder is assessed by direct shear strength under various loads using a rheo-powder cell. We start by measuring the mechanical properties of settled and compacted barite, which are relatively similar in all samples. Then, compared with typical cement G, settled barite presents low stiffness and mechanical strength. Finally, we compared the mechanical properties of settled barite powders from the field with those of unused sample from the laboratory. In both cases, the barite powder exhibits low flowability, i.e., it is extremely difficult to mobilize, and this increases with humidity. In this paper, new results on the assessment of settled barite as a barrier material are reported through various mechanical, ultrasonic, and imaging tests of a realistic settled and compacted barite from an oil field and compared to an oil well cement. In this case, we observed that the settled barite has poor mechanical properties for potential use as an additional barrier element. This could be link to the original formulation of the drilling fluids used and the conditions of use in the well.