bluuebunny/crossref_metadata_2025 huggingface dataset:
Revealing Time-Dependent Mud Properties Needed for Predicting Gel Breaking Pressure
Authors: Gjerstad K.
Published: February 2025

Gel strength measurements are routinely conducted on the drilling fluid on most drilling rigs today. They provide peak shear stress values during stress-overshoot measurements performed on a rotational viscometer, and they are among the few near-real-time metrics available to update drilling mud properties during drilling. Updated knowledge about the mud is crucial for predicting wellbore hydraulics and transient pressure surges during pump and string startup. However, although the gel strength measurements in a simplified way can be related to the yield stress of the mud, such correlations will in general not give correct pressure calculations. The reason for this is that both the gel strength and the pressure spikes are in addition dependent on the viscoelastic properties of the fluid and the acceleration of the fluid. This leaves a gap in how to utilize these measurements in the real-time prediction of the wellbore hydraulics. This paper contributes to fill this gap by providing simple formulas that can be used to estimate properties that are important for predicting transient downhole pressures for water-based fluids where bentonite is the dominating viscosifier. The inputs to these formulas are the standard gel strength measurements taken regularly on most rigs, and some parameters that are close to constants for the analyzed groups of drilling fluids. These constants are identified and quantified.
Novel High Temperature Water-Based Reservoir Drilling Fluid to Access Depleted Deepwater Reserves
Authors: King Conan , Rodrigue Kevin
Published: February 2025

High overbalances in high temperature-high pressure (HTHP) environments creates an unprecedented challenge for water-based reservoir drilling fluids (RDIF). Historically, oil-based systems have effectively controlled fluid losses at such extreme pressures. A novel high-temperature divalent brine-based reservoir drilling fluid (HT-RDIF) has been successfully deployed twice on HTHP wells for a Gulf of Mexico (GOM) operator, directly addressing this scenario. With ongoing depletion in the field, a redesign of the fluid was necessary to meet this new condition. Aqueous fluid solutions for highly depleted HTHP reservoirs have been a gap in the industry for many years. This paper describes the redesign process along with the qualifications and application on two reservoirs close to 7,000 psi depletion at temperatures above 320°F.

A HT-RDIF designed for standard overbalance between 1,000 – 2,000 psi was redesigned utilizing the same novel synthetic polymer technology as earlier wells in the field. Calcium bromide was selected as the base brine to minimize the amount of acid soluble solids in the drilling fluid as one of the wells would be an injector. A through qualification process was conducted to evaluate parameters such as rheological performance across a range of temperatures, long-term stability, fluid loss under elevated pressure of 5,000 psi overbalance and stress conditions (16 hours at 365°F), production screen tests (PST), and various fluid-fluid compatibility tests. Formation response tests (FRT) were performed on the final formulation to validate suitability for use.

At this time, there were limited commercially available Particle Plugging Apparatus (PPA) capable of greater than 5,000 psi. The operator had equipment capable of 10,000 psi. Halliburton commenced the building of a similar unit as the operator's PPA but capable of 12,500 psi. As well conditions continue to increase with pressure and temperature its critical to be able to test at near reservoir conditions as possible. At the time of this paper, an oil field testing equipment manufacture now offers a 10,000 psi PPA; however, a critical piece to high depletion wells is the extended duration testing and data acquisition capability of the equipment.
Determining Drilling and Positive Displacement Motor Dynamics Including Spectral Information With a Low Cost Sensor Package Integrated Into a Standard MWD Tool
Authors: Jeffryes Ben , Yang Libo , Bonderover Eitan , Weng Hans , Lesso Bill
Published: February 2025

Downhole dynamics and mechanics data have been acquired during drilling operations for at least forty years, but beyond simple shock counts and stick-slip estimation are still not routinely used to aid the driller either in real-time control of the drilling process or post-well analysis. The barriers to doing this include equipment cost and reliability, telemetry bandwidth from downhole to surface, and availability of expertise in data interpretation. In this paper it is shown how valuable drilling dynamics information can be acquired using accelerometers and magnetometers integrated into a standard mandrel D&I tool, as used in most directional drilling operations. In addition to time-domain statistics, high frequency accelerometer data is processed downhole to provide frequency-domain spectral information, which in combination with rotation speed information derived from magnetometers can be used to monitor the performance of downhole tools such as drilling-motors and friction-reducing vibration tools, as well as detecting drilling dysfunctions such as bit-bounce, bit-sticking, and whirl.

After describing a new drilling dynamics module (DDM) used to acquire the data, case studies of data and its analysis are shown. Firstly, in monitoring of motor and friction-reduction tool behaviour using data acquired above the motor in a standard directional drilling configuration. Secondly, in applications where a motor is combined with a rotary steerable tool, and the DDM is between the motor and the bit, showing how damaging dysfunctions such as bit-stopping, bit bouncing and forward-whirl can be reliably detected.
Comparing Polycrystalline Diamond Compact Cutter Stress to its Structural Integrity When Drilling Interbedded Formations
Authors: Cherry M. M. , Pastusek P. E. , Payette G. S. , Bijai R. R. , Gjertsen O. J. , Durairajan B. , Gan X. , LeBaron A. M.
Published: February 2025

Measurement of the strength of materials and calculation of applied and residual stress are fundamental to mechanical engineering design and the continuous improvement of mechanical systems and processes. This paper uses these fundamental principles to establish an enhanced engineering framework and workflow for drill bit design, application, and drilling process improvements. It also highlights improvements in modeling and experimental data collection that are needed to continue to improve the drilling process.

Transient rock-cutting models are used to calculate the contact stress on the face of polycrystalline diamond compact (PDC) cutters on drill bits. This is applied to finite element models (FEM) of the cutters to calculate the maximum principal stresses. This process can be used to study the effects of bit profile, blade count, and cutter density on the maximum principal stress while drilling at different penetration per revolution (PPR) in various formation hardnesses. These stresses are compared with a forensics study to find instances of tangential overload-induced fractures to determine the maximum PPR a given PDC bit design can withstand for a given rock strength and application.

When drilling homogeneous or interbedded formations, it is necessary to control the PDC cutter stress below its structural limit. One method to do this is to create roadmaps of the acceptable parameters (particularly PPR) to reduce unwanted tool failures and trips. Roadmap creation is often experimental and fine-tuned with field development. With the outlined workflow, digital data from offset wells and forensics observations can be used to calculate stress for specific designs and applications. Along with estimations of a particular cutter's tangentially loaded structural integrity, this can be used to create much more accurate roadmaps of the drilling system's capabilities.

Computation of the dynamic stress required to fail cutters is a major improvement for the industry. It makes the design process and parameter recommendations based on well-established engineering principles. This process is continuously improved as the experimental and modeling capabilities are upgraded.

Specific guidance on maximum allowable PPR as a function of confined compressive rock strength can now be given to reduce uncertainties in roadmap creation. Bit designers can study the effects of bit profile, blade count, cutter density, and depth of cut (DOC) elements on the peak cutter stress while drilling interbedded formations, and bit selection of existing designs is now put on a firm engineering basis. This is a significant improvement over the maximum weight on bit (WOB) recommendations used today.
Digitalization of Connection Practices to Prevent Transient Drilling Dysfunctions
Authors: Li D. , Shen Y. , Tang K. H. , Chen W. , Zhang J. , Al Jarad C. , Simon A. , Converset J.
Published: February 2025

Total well delivery time is becoming the primary performance metric in well construction. This drives operators to increase on-bottom penetration rate and reduce time spent performing off-bottom operational steps, such as connections. This paper introduces a new method to digitalize each connection, define optimal practices, and ultimately avoid costly transient drilling dysfunctions. The method combines an advanced physics-based simulation package with cutting-edge digital and data science tools.

Multiple failures, such as twist-off events, overtorqued connections, and back-off events, were investigated across various applications. Many of these failures were caused by transient downhole dynamic events when transitioning between operational steps. Picking up off-bottom, tagging bottom, starting rotation, and starting flow are the main examples of the critical steps during connections.

A comprehensive physics-based model was developed to replicate these transient dysfunctions. The model revealed what attributes of the connection process cause dysfunctions. Performance indices were computed from those relevant attributes to characterize each connection in digital form. A new computation engine was developed to automatically compute these indices. The engine was deployed both in real time for drilling monitoring purposes and in the cloud for deeper big data studies in the future.
Unlock the Potential of High-Resolution Ultrasonic Imaging and Caliper Measurements for Large Borehole Sections
Authors: Carrilero S. Gutierrez , Hinz D. , Wong S. M. , Jin J.
Published: February 2025

Obtaining high-resolution ultrasonic caliper measurements and amplitude images in oil-based and water-based mud from logging-while-drilling (LWD) tools has become a common practice for hole sizes up to 14.75-in. in diameter. This paper introduces a new LWD high-resolution ultrasonic caliper/imager tool designed for hole sizes up to 19 in. in diameter.

The insight gained with smaller ultrasonic tools has revealed that a 9.5-in. tool would require a distinct ultrasonic transducer to account for larger standoff distances in larger boreholes. The new 9.5-in. tool utilizes an ultrasonic transducer with a lower nominal frequency than the smaller tools. Laboratory and field trials confirmed the 9.5-in. tool's capability to capture high-resolution borehole images and caliper measurements in boreholes up to 19 in. with varying mud weights. The tool's eccentricity-corrected amplitudes and radius images improved borehole geometry analysis and geological feature identification. The high firing rate of the transducers and four-transducer design allows for obtaining an average caliper size while tripping out of the hole without rotation and enables accurate cement volume calculation. Additionally, while reaming out of the hole, the borehole shape can be evaluated to understand its behavior over time after drilling, providing valuable information for the operator.

The data collected during field trials was analyzed and compared with wireline ultrasonic tools from the same area to validate the results. The interpretation of the borehole images (amplitude and travel time) for both borehole geometry and geologic features confirmed a spot resolution of 0.2-in. while drilling with different logging and rotary speed combinations. The development of a new 9.5-in. LWD high-resolution ultrasonic caliper/imager tool has resolved the challenge of obtaining caliper measurements and borehole images in larger borehole sections. This innovative tool will significantly enhance operators' ability to perform cement volume calculations and accurately identify unstable formations in larger boreholes.
Casing Swivel: A Key Enabler in Aiding the Longest Liner Deployment in Offshore Umm Shaif Field, UAE
Authors: Wong C. , Fomekong F. , Prasetyo B. , Al-Hajri S. S.
Published: February 2025

With the growing trend of drilling 30,000+ ft horizontal wells from an offshore WHT slot, a new level and specific approach are required to enable successful liner deployment to well TD. This paper describes the well challenges and the use of a casing swivel application in liner deployment that helped complete the longest liner in the deepest drilled well in the Offshore Umm Shaif field, UAE.

The recent well design of a 30,000+ ft well rendered the operator's previous approach of using the drill pipe swivel irrelevant. While the market offers casing swivel technology to reduce drag force and aid liner deployment, the optimum intervals where the casing swivel should be placed along the liner must be thoroughly assessed as both compression and tension force acting on each specific placement depth may compromise the casing swivel bearing lifetime and performance. A series of torque and drag simulations were run with a variance of casing swivel placement depth to achieve this optimum value.

By optimizing the placement of the casing swivel at 3,485ft below the liner setting sleeve, enabled a large section of the string to be rotated while decoupling torque to be transferred down below the casing swivel. The swiveling effect resulting in axial frictional drag reduction, alleviates buckling risks and provides more weight at the surface to push the liner to TD. In this case, the collaboration between the operator and technology provider yielded a successful deployment of 17,678 ft of 6-5/8" liner on a 30,000 ft MD horizontal well.

The liner was stalled and could not be deployed under the conventional deployment at 28,100 ft MD due to drag and buckling events. After attempting to wash down without any progression, rotation was then initiated with the help of the casing swivel at 20 RPM and 4 BPM circulating rate, which successfully completed the existing stand. Subsequently, the rotation continued for the last 1,892ft at a controlled tripping speed where it finally landed at well TD.

The casing swivel saved approximately 5 days of rig time, avoided NPT and completed the jobs efficiently and safely. It also enabled the operator to complete a long lateral section, maximizing and extending beyond the boundaries of typical offshore wells. Proper placement of the casing swivel technology enabled the liner string to be deployed in the challenging offshore jack-up rigs, increasing the success rate of liner deployment, and saving overall cost and time, avoiding the need to POOH the failed liner string and run an additional wiper trip.
Near-Bit HFTO Damper Enables Significant Drilling Performance Increase in Global Case Study
Authors: Hohl Andreas , Mihajlovic Saša , Fawaz Hassan
Published: February 2025

The drilling performance of rotary steerable systems is defined by the capabilities of the surface and downhole system, the bit, the formation, different functional aspects such as hydraulics, and is limited by dysfunctions that constrain the operational parameter envelope. One such constraint is vibrations that limit the drilling efficiency and can result in premature damage of the bottom-hole assembly (BHA). High-frequency torsional oscillations (HFTO) are a particularly damaging vibration mode that cause failures at sensitive electrical and mechanical components through high acceleration and dynamic torque values. To prevent these damages, the operational parameter envelope and the bit and BHA design options are constrained which compromises the drilling performance.

The paper introduces a steering unit with HFTO-damping capability which was designed to overcome these limitations. The inertia-based damper is implemented in a component of the steering unit close to the bit. The placement close to the source of the vibration enables an effective mitigation of HFTO, as suggested by theoretical considerations, simulations, and lab testing. A worldwide case study with >50 deployments covers representative applications/BHAs, environments and formations.

In the case study a reduction of damaging HFTO of typically 100 % (and at least by 99 %) compared to offset runs was achieved. Third party vibration mitigation tools were significantly outperformed regarding HFTO reduction. The data confirms a significant improvement in reliability and re-run capability of the deployed BHAs. After proving the HFTO mitigation capability, the weight on bit and bit rotary speed limits were increased resulting in a significant increase of the rate of penetration (ROP). The drilling parameter increase enabled record runs in specific applications discussed in the paper.

In summary, HFTO effectively disappeared with the introduced steering unit. This in turn allowed for an increase in Weight on Bit (WOB) and bit rotary speed, opening the operating parameter envelope, resulting in achieving an even higher rate of penetration. The early study proves a significant cost saving potential enabled by higher reliability, lower non-productive time, and increased drilling efficiency and ROP. The results create opportunities for the introduction of new rotary steerable designs that were previously unattainable.
Drill Pipe Connection Inspection Optimization
Authors: Plessis G. , Delcambre D. , Tumlinson J. , Cunningham K.
Published: February 2025

The latest generation of drill pipe connections was designed to bring a low cost of ownership, which was confirmed by monitoring the inspection data of hundreds of thousands of connections over the last few years. It established that the 4th generation of double-shouldered connection offers a lower percentage of connection recut, typically half that of other connection designs. However, some users sporadically reported seeing a very different picture, with recut percentages in excess of 50%.

This started a reinspection project by the original equipment manufacturer's (OEM) field personnel, using its procedure and taking advantage of the connection design's tolerance for damage. The project included performing minor field repairs on surfaces that qualified. The focus was specifically on the connections marked for recut and ignoring those marked for reface or passed.

the same principle of reinspection according to the OEM criteria was used by a major rental company, using an independent source to determine whether the initial inspection data accurately reflected the reality of a string that suffered hard drilling conditions or was being over-inspected.

In both cases, we found reinspection numbers showing a very different picture, with cases where the number of connections needing recut fell by more than 90%. A need for fast inspection turnaround drives this practice of over-inspection as the rig moves to the next pad. It also provides comfort by removing the risk of making a bad decision. Marking the connection for repair is fast and safe and requires minimal effort. However, it pushes, on average, two to three times the volume of connections toward a workshop repair.

And this massive swing in numbers impacts the cost of asset ownership. More drill pipe may be needed on-site to cope with the volume that is out for repair, or some may need to be rented to top up the string. This process involves more transportation. A bottleneck may form at repair shops where additional cost is incurred to recut these connections. Finally, some asset life is lost as connections can only be repaired a limited number of times before tool joints are too short to be clamped on.

For the first time, a thorough study of connection repairs will be shared, with a focus on connection recut numbers. It shows how a reclassification of the inspection can greatly save time, money, and asset life.

As a result of the study, a new service has been created to correct, when needed, possible situations of over-inspection. Its objective is to gently push the industry to adopt the new inspection criteria set by the OEM.
Towards Johan Sverdrup Field Development Optimization and Concept Robustness Using AI Assistance
Authors: Les B. , Tjøstheim B. P. , Sørbel J. , Ulvedal L. , Dolle N.
Published: February 2025

This paper introduces an artificial intelligence (AI)-assisted methodology for rapidly screening multitude field development concepts across cost and risk domains. The methodology, matured over the last years, has been applied to the early-phase Johan Sverdrup Phase 3 Field Development Project (FDP), the company's digital frontrunner, with aim to improve the project's economy while ensuring robust infrastructure placement and expedited CAPEX screening.

The methodology integrates evolutionary algorithms to generate sets of possible and feasible well trajectories for considered development targets. Feasibility is ensured adopting the field-specific well concept and associated drilling rules, whereas all possible solutions are evaluated through greedy exploration of a large option space. This is combined with a second solver that optimizes well- to-template allocation and subsea template placement, ensuring that subsurface hazards are avoided and either the total project cost or drilling risk is minimized. Simulated results are presented in an online user interface and analyzed through a digital data report, facilitating evaluation of multiple concepts and the associated cost-risk trade-offs.

The study demonstrates a novel fast-track methodology for screening tens of thousands of drilling and surface combinations, significantly accelerating concept comparison and identifying new, relevant FDP solutions. Data generated by this methodology was used for internal validation of project assumptions and refinement of concept selection as the project matures towards the final investment decision. Results of study highlighted data-driven concept improvements, sensitivity analysis of reference concept sensitivities, and benefits of human-centered evaluation of solution space. Extracted learning resulted in more efficient use of engineering resources and time, channeling them towards the subset of most promising FDP solutions.

This case study represents the first application of an AI-driven approach to field development optimization in this context, replacing traditionally manual, discipline-specific processes. The proposed methodology enables a more efficient and streamlined insight retrieval, thus facilitating resource-allocation and improving decision-making for future field development projects.
Openhole Logging Utilizing a Statically Underbalanced Mud Weight in a Narrow-Windowed Extended Reach Well: A Case for Closed-Loop Dynamic Annular Pressure Control in Logging Operations
Authors: Khalid Ali , Ruiz Carlos
Published: February 2025

An operator was performing reentry operations in existing vertical wells to drill an extended lateral section across the reservoir formation. The carbonate reservoir exhibited faults and fracture networks and, with pressure depletion over time, presented a narrow operating margin for drilling and all subsequent operations.

Despite the operator’s intention to perform openhole logging across the complete openhole interval, the use of conventional drilling fluid and pressure management plans proved to be severely limiting. These methods, when attempting to navigate through tight operating windows, often led to issues such as total circulation losses, influxes from the reservoir, hole instability, and stuck pipe events. This underscored the need for a more effective and efficient approach.

To reduce operational complexity, the conventional practice is to have a balanced mud weight inside the wellbore while logging operations are being conducted. However, in the case of a narrow-windowed well, displacing a sufficiently heavy kill fluid can cause the equivalent circulating density (ECD) to exceed the minimum fracture gradient of the section, and displacing to a lighter kill fluid will potentially result in an underbalanced condition as a sufficient trip margin will not be maintained. Therefore, a proposal was made to utilize a statically underbalanced mud weight in the section and maneuver the annular pressure profile just above the pore pressure line by utilizing a closed-loop managed pressure setup.

A managed pressure engineering design was performed to optimize the ECD management plan, and a specialized logging string was designed to contain two specialized barriers that would allow for the logging tools to be passed and deployed outside of the string. The logging string was to be stripped out of the hole through a rotating control device, closing the loop on the annulus, while the managed pressure system maintained the required equivalent mud weight profile at the targeted depths across the openhole.

The openhole logs were conducted as per plan, stabilizing the statically underbalanced wellbore by actively managing the annular pressure profile across the target section. Contributions to the industry include the design methodology, the sequence of execution at the wellsite, and documentation of the results achieved in the application of managed pressure openhole logging on the subject well.
Assessing Drill String Component Health Through Predictive Digital Analytics
Authors: Belov Dmitry , Chen Wei , Liland Eimund , Malik Asim
Published: February 2025

A cutting-edge solution enables accurate prediction of the remaining useful life (RUL) of drill string components before deployment in the field. This proactive approach allows informed decisions about such components to be made prior to actual drilling, significantly reducing the risk of field fatigue-related failures. The solution provides an efficient and cost-effective method for extending the lifespan of critical components, such as BHA connectors, ultimately improving overall operational efficiency.

The solution seamlessly integrates drill plan data with results from offset well analysis to estimate the RUL of various drill string components, particularly different BHA connectors. By examining offset wells with similar equipment and geological conditions, it extracts essential anticipated operational parameters. Combining a physics-based model of the relevant drill string components with a data-driven approach and modeling capabilities, the solution ensures reliable decision-making regarding the suitability of specific components for particular drilling operations. Additionally, it facilitates the optimal selection of drill string components for the intended job.

This innovative solution has undergone extensive testing, leveraging historical data to validate its reliability and effectiveness. A comprehensive comparison of predicted RUL for monitored components before field runs with actual post-job RUL estimates based on recorded drilling time consistently demonstrates favorable outcomes. This rigorous validation confirms the accuracy and dependability of the approach.

By implementing this solution, drilling engineers can optimize drill string component selection, configurations, and maintenance operations, minimizing uncertainties in RUL estimation and reducing the risk of costly failures. Integrating predicted RUL estimates into routine post-job maintenance before starting new drilling runs enables well-informed decisions, preventing unnecessary maintenance and mitigating premature component retirements.

The solution is now thoroughly validated and ready for seamless integration into a comprehensive drilling platform, encompassing maintenance systems, well construction planning, and execution. This unified strategy for drill string component management maximizes equipment utilization, enhances drilling performance, and ensures reliability throughout the drilling process. Operators adopting this integrated approach can optimize fleet management, reduce nonproductive time, minimize associated costs, and ultimately maximize revenue.

This solution highlights the significant value digital technology brings to traditional mechanical systems in the oil and gas industry by enhancing functionality and creating new service opportunities. The described algorithm and its validation process are novel to the industry. Several instances analyzed demonstrate the methodology's application, providing valuable comparisons to post-job results and underscoring the approach's robustness.
Well Construction Difficulty Index – A Modern Benchmarking Tool for Drilling
Authors: Dow Blaine , Manescu Gabe , Haq Shahid Azizul , Escalera Hernan Melgares , Rodas Mauricio Pena , Dhaher Karam Sulaiman , Abuelaish Ahmed Rami
Published: February 2025

In 2000, Oag and Williams (IADC/SPE 59196) introduced Directional Difficulty Index (DDI) as a benchmarking tool aimed at normalizing trajectory complexities across wells. The tool was designed to establish expectations of directional drilling performance from well to well, and serve as a planning tool for optimizing projects. Equally, where drilling teams desired, it served as a means of leveling performance incentives from well to well. In the interest of simplicity, DDI focused exclusively on trajectory, wellbore length, TVD and tortuosity. The uptake of DDI has been successful, yet the original authors acknowledged future work could broaden the application. This body of work is intended to expand the concept of DDI to incorporate additional complexity factors.

Items within the control of the planning team will include wellbore architecture, drilling rig capabilities, drillstring, bit and BHA selection, drilling fluid, casing and cementing plan. It will also include in-situ factors such as rock characteristics (homogeneity, rock strength, abrasiveness) borehole pressure and temperature challenges, and the location and environment of the drilling location. Consideration for well characterization and reservoir steering objectives, while drilling, coring or post drilling will be incorporated. The completion method will also be considered, in context of how it pertains to drilling. Less conventional well constructions methods such as casing while drilling, multi-lateral drilling, MPD and coiled tubing drilling, will also factor.

This document is intended to be a first iteration of Well Construction Difficulty Index (WCDI). The desired outcome will be an industry tool that offers a means of normalizing technical challenges for a given hole section, in as simple a form as possible, to drive project decision making. It will help drilling teams more effectively select and prioritize technical solutions for their wells during the design phase and measure relative execution performance across many wells. Applied correctly, WCDI will help rand risk and set appropriate expectations, while also facilitating mechanisms that can appropriately drive incentive contracts.
A Probabilistic Framework for the Risk-Based Evaluation of Drilling Plans
Authors: Daireaux B. , Ambrus A. , Moi S. , Cayeux E.
Published: February 2025

During the well planning stage, several alternative designs are considered, and a team of experts then has to identify the optimum one according to possible contradicting criteria such as performance, cost, logistics, or safety.

This selection can be challenging, and several key aspects may be ignored to simplify and accelerate the process. In particular, the impact of uncertainties on the main criteria is notoriously difficult to measure and include in the analyses.

The objective of the presented work is to develop a software platform that facilitates the analyses involved and enables the end-user to make informed decisions at the planning stage. The developed system has to cope with the presence of uncertainties, the possible occurrence of incidents that may affect overall drilling performance, and a large variety of possible scenarios. The analysis of a given well plan relies on Monte-Carlo simulations of the drilling process, including potential malfunctions or incidents and their impact on the operations. The propagated uncertainties can subsequently be analyzed through a dedicated logging mechanism that enables the user to specify drilling metrics of interest.

The combination of modern software architectures and advanced numerical models makes it possible to obtain detailed evaluations of a given well plan. We provide examples of such analyses and show how our probabilistic simulation framework can capture a large variety of relevant metrics. The end-user is then free to select the most appropriate one to finally assess the quality of the proposed plan and compare it to alternatives. Additionally, it becomes possible to incorporate learning mechanisms to optimize several operational procedures during the planning stage: this may in the future form the basis for a direct connection between well planning and automated execution.

A simulation framework is presented that aims at capturing the effects of uncertainties early at the planning stage. By quantifying risks and performance metrics, it provides the end-user with realistic estimates of the plan's quality, helping them make informed choices among the available alternatives.
Limiter Redesign Workflow Yields Positive Results in Deep Geothermal Drilling in Switzerland
Authors: Garcia A. , El-Alfy A. , Noynaert S. , Centala P. , Wojaczek D. , Moldoveanu S.
Published: February 2025

As companies are considerably increasing geothermal energy as a crucial element in their decarbonization strategies, the need to reduce costs and increase efficiency in hot hard rock drilling is gaining significant importance.

The lessons from FORGE (Frontier Observatory for Research in Geothermal Energy), a U.S. Department of Energy (DOE) geothermal project in Utah that started in 2020 over a 5-well program, were implemented using the same physics-based practices workflows developed by a group in Texas A&M University, aimed to reduce flat time generated from key performance limiters such as BHA whirl, lack of weight transfer, resonant RPM, and other parameters that accelerate drilling dysfunctions.

To reduce the drillability uncertainty into hard rock in the Switzerland project, evaluation of core samples extracted from 3 different offset wells yielded conclusive results. The lithologies included Monzonite, Metapelite and Granite, representing different grain structures. These were analyzed in the laboratory for single PDC cutter testing at different depths of cut. One of the three samples required 10-15% higher forces both axially and tangentially, suggesting a higher compressive strength compared to the granite found at FORGE.

Rapid bit iterations were critical to extend the cutting structure longevity and rate of penetration based on dull conditions seen in each run. These included different body configurations and PDC cutter grades and shapes that would perform optimally under typical higher weight on bit using high torque motor and rotary assemblies.

The combination of a good BHA design, the use of aggressive bits with shaped cutters and maximizing WOB resulted in reduced vibration levels as recorded in the MSE (Mechanical Specific Energy) trends and bit dulls led to better drilling performance. Physics- based practices training and re-training for all people involved played a significant role in achieving such results.
ORCHYD: Combination of High-Pressure Water Jet and Percussion to Improve Drilling Performance in Hard Rocks
Authors: Gerbaud L. , Velmurugan N. , Jahangir E. , Sellami H. , Cazenave F. , Latham J. P. , Xiang J. , Naderi S. , Kane P. A. , Dumoulin S.
Published: February 2025

Drilling through hard crystalline rocks like granites is challenging and taxing on the overall performance due to reduced rate of penetration (ROP). While efforts have been made in improving polycrystalline diamond compact (PDC) bits to increase ROP in hard rocks, the evidence of their field performance is currently restricted to only a few sites. There exists scope for alternative drilling technology where a significant fraction of hard rocks are present, such as in deep geothermal wells for electricity generation.

In the ORCHYD project, two mature technologies – high pressure water jetting (HPWJ) and percussion drilling - were combined. A combination of bit profile and peripherical groove (slotted by HPWJ) creates a stress-relief effect releasing the rock from surrounding geological stresses, requiring lower energy to break the rock using a mud hammer. Furthermore, pressure waves due to percussion are reflected by free surfaces at the groove aiding in rock breakage. In this project, an experimental study on the influence of operating conditions such as HPWJ pressure, bottom hole pressure and surrounding geological stresses on the drilling performance was conducted.

Several tests were performed at a dedicated drilling laboratory where the operational parameters can be varied to emulate drilling conditions for depths up to 4 km. As compared to tricone roller bits, ORCHYD technology guaranteed at least 4 times increase in the drilling performance. The performance of HPWJ in slotting a peripheral groove and mud hammer in rock breakage were strongly influenced by the operational conditions, e.g., for a given jet pressure the groove depth decreased significantly with increased bottom hole pressure. In this work, effects of such operating conditions on drilling performance were tested for different types of rocks such as Sidobre, Kuru Grey and Red Bohus. A sensitivity analysis of the influencing parameters on drilling performance of this technology is presented in this work. With increasing geological stresses, the proposed drilling technique is more effective in increasing ROP due to the stress relief effect.

A novel technique combining HPWJ and percussion drilling using a mud hammer prototype was developed to show improved drilling performance in deep, hard rocks as compared to conventional drilling technique. Through this work, the performance of this method under different realistic drilling conditions was studied to optimize ROP, especially when drilling hard abrasive formations in deep oil and gas or geothermal wells.
The Automation Advantage: Efficiency Improvements in Offshore Drilling
Authors: Millward B. , Kabi B. , Marck J. , Laing M. , Welmer M. , Reber R. , Kjøsnes I.
Published: February 2025

Automation has progressively taken over various manual drilling subprocesses on selected rigs for one Norwegian operator. In the past year, notable advancements in automation have been achieved, which orchestrate automation procedures across disparate surface and subsurface systems into a unified platform for control. This paper presents the tangible benefits these initiatives have yielded, notably enhanced operational efficiency and safety as well as improved efficiency of workflows for the drilling crews.

This paper will detail the technological innovations employed in this project, the verification and validation steps that preceded full-scale implementation, and the practical impact the automation solution is having on operations. The paper will elaborate on how the solution enables orchestration across multiple engineering solutions in conjunction with the rig control system to ensure a state-managed set of critical drilling parameters is utilized to deliver precise actuation aligned with the current rig process. It will also discuss the process of establishing connectivity between the parties involved in both a technical and operational capacity.

This project represents a revolutionary step in offshore drilling, showcasing the successful collaboration, integration, and orchestration of automated technologies in a complex operational environment involving multiple actors. We will provide a detailed review of the project’s objectives, which centered on demonstrating the feasibility of autonomous drilling operations to function over an extended period.

The project demonstrated successful interoperability of processes aligned with best practices between downhole and surface controls across multiple partners, on a robust system for exchange platform. In addition to reviewing what worked well, the paper highlights several learnings on the relevance of integrated process boundaries for lower-bounds management in system control.

The paper will explore the implications of these results for future offshore drilling operations, emphasizing the potential for widespread adoption of autonomous drilling technologies. It will reflect on the project’s contribution to the field of automated drilling and its alignment with industry goals of safer, more efficient, and consistent practices.
An Ontology of Well Engineering Entities to Extract and Structure Text Data from Daily Reports
Authors: Queiroz J. , Jaculli M. A. , Choueri Junior N. , Silveira I. M. , Mendes J. R. P. , Penteado B. E. , Guilherme I. R. , Perrout S. R.
Published: February 2025

Oil and gas activities generate, inevitably, huge amounts of data, especially in the form of Daily Operational Reports during construction and production activities. Extracting information from these reports can be achieved using embeddings combined with Large Language Models (LLMs), with domain knowledge being mandatory for this extracted information to be meaningful and properly presented to end-users. A solution for this challenge is the use of Knowledge Graphs (KG) to organize and relate all the information in a way that properly represents the concepts (e.g., entities, events, and processes) of the specific domain. A KG can address the lack of domain knowledge presented by LLMs, as well as enhance the semantics of embedding-based indexes such as those provided by Transformers, but also as a searching source itself that enables to take advantage of the information relationships (i.e., the natural links between entities or pieces of data). However, the creation of a KG from a specific domain based on unstructured data sources requires not only an ontology to describe the entities and their relationships but also strategies and tools capable of properly extracting and mapping them from the data sources to a KG. In this context, this work proposes a well engineering ontology to guide extracting information from Daily Operational Reports, structure them into KGs, and support information retrieval applications. To assure interoperability, the development of the proposed ontology is aligned with upper-level ontologies and industrial standards like ISO 15926. The results of this work include not only the ontology itself and the procedure followed to build it, but also a discussion of further applications that can be developed using it as a basis. The main applications resulting from this work are named entity recognition, visualization of incidents, classification of operations, templates and auto-filling of reports, calculation of drilling metrics, and queries within the reports database. We have noticed that having structured domain knowledge, in the form of an ontology and KG has improved the success of these applications compared to raw text processing. Finally, this work emphasizes the importance of domain knowledge in the form of a comprehensive ontology that focuses on the relevant entities of the application domain and enables the creation of KGs that can facilitate the organization and query of complex unstructured text information and enhance data analysis and LLM-based applications in the Oil&Gas domain.
Optimizing Operational Processes and Reducing Equipment Failure Through a Real Time Alerting Platform
Authors: Martinez S. , Godumagadda A. , Pandey B. , Malliganuru N.
Published: February 2025

The ability to monitor data in real time has become increasingly important as the industry continues digitalization efforts. Over the past several years this contractor has upgraded the capabilities of a real time monitoring system that has been providing value through improved operational efficiency and visibility of operations across its onshore fleet. These updates open a wide set of alerting opportunities that were previously not possible by distributing the alerting system to local, rig-based devices. An overview of the technology and architecture necessary to make this system possible, as well as the impact on performance will be discussed.

This contractor's efforts have focused on converting the system from a cloud-based system to an edge-based system, with all computations and alerts issued at the rig location. The architecture comprises migrating cloud applications to run on the edge and leveraging edge hardware and rig historians to enable alerting on all data available at the rig location. Streamlining and synchronizing the rules/alert definitions and notifying users instantly using cloud infrastructure is a novel implementation. Housed within the edge platform, the system can operate on batches of data in real time without being held back by cloud computing related latency.

Preexisting infrastructure made it possible to receive exception-based alerting within 15 minutes of an event occurring. With the new implementation running on the edge, it is possible to receive alerts to the user's phone, email and/or web-based dashboard within a minute. Leveraging increased real-time monitoring capabilities, this contractor has been able to reduce the amount of premature equipment failures as well as improve drilling connection operations. These successes have resulted in a reduction in capital spend and improved spud to release times. The above will be reviewed in detail.

This change in data architecture from a cloud-based to a distributed rig-based computing system provides a more efficient way to trigger alerts and opens the possibility of generating alerts locally at the driller's console. Previously, the cloud-based alerting system only had access to data streamed off-location, providing limited insight into equipment health and drilling conditions. As a result of this update, we can provide end users with alert notifications containing detailed messages and specific data from a wide range of local data sources, including thousands of equipment-related data feeds, downhole data, complex artificial intelligence(AI)/machine learning(ML) model outputs, and drilling performance metrics which were not previously synchronized into a system that allowed alerts to be generated across this entire dataset. Quicker computing and notification delivery times will pave the way for well control, drilling dysfunction and more sophisticated equipment health alerts on the driller's console in real time.