bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Study: Deep Insights from Downhole Sensing Unlocks Extended Bit Footage for Economic Drilling of Vibration Prone Abrasive Sandstones in Central USA
Authors: Hanafy A. , Kueck A. , Pauli A. , Huang X. , Bomidi J.
Published: February 2024

Targeting deep reach laterals in vibration prone interbedded abrasive sandstones requires multiple bits to complete the prolific pay zones in Central USA. Excessive cutter wear coupled with extreme torque fluctuation in such targets results in reduced ROP and premature failure of BHA components. Early POOH leads to 24 to 48 hours of non-productive time due to BHA tripping. This puts huge economic risk on such challenging pay zones. This study exhibits detailed analysis of downhole and in-bit sensing data to increase the operational stability window enabling enhanced bit durability and smoother drilling conditions for economic drilling of long laterals.

The proposed bit's operation optimization framework is built using a detailed analysis for an in-bit high-frequency sensing gyro and accelerometers data correlated to the geo-steering unit vibrational and Gamma-ray data. The data analysis identified High-Frequency Torsional Oscillation (HFTO) prone formations and HFTO event frequencies, amplitudes and durations while drilling through lithologies with different rock strengths. The findings from the analysis of the field data are cross referenced to the bit response in lab experiments using in-bit sensing while drilling custom built rock cores under high confinement pressure. The result of this work is used to accurately model the drill bit performance to develop best practices to operate them. An operational stability map and a drilling guideline were built and communicated with the region for longer reach and stable drilling.

The data analysis showed a correlation between the lithology shaleness factor and the bits susceptibility to trigger HFTO among other vibrational events. The higher the shale content on the GR track the lower the HFTO excitation probability. These findings were mirrored in the lab while drilling interbedded cores at high confining pressure and it was used to calibrate our drilling models for bit optimization. The application of the drilling guidelines on operating 9 bits resulted in a total savings of $500K per well and 4 days less of non-productive tripping. The guided drilling practices increased the drilled footage per bit by 50%, while reaching the same dull state as previous runs. The control of the bit HFTO and vibrational response decreased the frequency of premature BHA equipment failure enabling longer intervals and less unnecessary tripping.

The absence of wire line logging in long reach laterals limits the understanding of targeted zones. This framework enables gaining deeper formation insights that unlock the optimization of capable drill bits. The adoption of such practice is promising longer footage per bit, less downhole vibrational issues, and economic completion of challenging interbedded abrasive across the world.
Mitigating Drilling Dysfunction: Stopping HFTO Where it Starts
Authors: Johnson Ashley , Panayirci Murat , Scott Dave , Gjertsen Ole , Cazares Lucia
Published: February 2024

This paper presents development of a system to test the origins of high-frequency torsional oscillation (HFTO) and identify the physical cause that allow for building information, which will alleviate this damaging dysfunction.

It will present field data where the actual amplitude of HFTO is a complex function of many parameters in which both drill-bit speed and weight on the bit are extremely significant. The HFTO amplitude will increase with both parameters to a peak and then a further increase will reduce the actual vibration.

To characterize these relations, a facility was built in our Research Centre in Cambridge, UK, to test HFTO in a laboratory environment. A torsional equivalent to a mass spring resonator was used. The facility allows for drilling under identical drilling conditions with HFTO enabled or disabled.

It will be shown that the origin of HFTO is at the actual cutting structure contact with the formation. The HFTO is not driven by the broadband bit drilling noise but by the actual bit cutter's interaction with the formation rock. It is these interactions that drive the speed and weight on bit (WOB) characteristics observed in downhole operations.

The characteristics and scale of the dysfunction are dependent upon the formation, the cutting structure, as well as the cutter profiles. This new knowledge will enable bits to be built that will alleviate HFTO rather than drive it.
Using Big Data to Spotlight HFTO
Authors: Bhoite Sameer , Johnson Ashley , Mukhtar Adeel , Long David , Singh Suchita , Peot Nicholas
Published: February 2024

High frequency torsional oscillation (HFTO) is a major contributing factor to the drilling dynamics-related bottomhole assembly (BHA) failures. These failures are costly because they not only damage the drilling tools but also cause significant nonproductive time (NPT) to the operational activity. It is therefore highly desirable to measure and mitigate this dysfunction in real time.

We have built a high-performance drilling dynamics module, which enables real-time or recorded mode measurements of this HFTO phenomenon. Using this measurement, we can deliver actionable insights to the rig or the rig crew in real time. With data from more than 3000 runs, we can build a clearer understanding of the real characteristics of HFTO, its drivers, and the effects it has on our drilling systems.

We show that with increasing Weight on Bit (WOB) the amplitude of the HFTO will increase. However, at high WOB the dysfunction amplitude will drop, while the ROP continues to rise. As such there is a sweet spot with high ROP and low HFTO.

By integrating this database of drilling dysfunctions with our records of tool damage and nonproductive time, we can map the effect of HFTO onto different failure criteria. As a result, we can define new and better operational standards and generate real-time insights into what damage is more likely to occur and how to change drilling parameters, if needed, to prevent it or determine if the vibration will pass without incident.

We also show that although the rotary steerable tools we use are sensitive to the effect of HFTO, our measurement while drilling (MWD) tools are not. For this latter group the probability of damage is the same for runs with and without HFTO.

This paper discusses the method and results for this study.
Saving Pipe One Joint at a Time: The Use of Welded Wear Bands to Protect Drill Pipe Tubes in Abrasive Formations
Authors: Wells Austin J. , Doles David , Tappin MaeBeth , Reese Jobe A. , Morgan Ryan , Kroger Jason , Horton III Tom , Anderson Mark , Broussard Steve
Published: February 2024

As operators actively manage their costs of drilling, reducing cost in one area can increase it in another. Millions of horizontal feet drilled across North American shale basins has effectively eradicated existing drill pipe fleets. In addition, the rise of 5-1/2 inch variants in land-based Extended Reach Drilling (ERD) wells has made drill pipe more difficult and costly to replace, so keeping drill pipe in service for as long as possible is paramount to improving its total cost of ownership as well as to ameliorate the risk of replacement when supply chains preclude availability. In two continuous trials, drill pipe was protected using welded wear bands near the center of the tubes, with the downhole effect on the pipe carefully measured and analyzed.

Using a ground-breaking, low heat input welding process, protective weld material was applied to drill pipe tube bodies used in the Jonah Field and Midland Basin. These protected the most vulnerable areas of the tubes from wear and mitigated DBR/downgrade. The protected drill pipe was thoroughly inspected after being used in both the Jonah Field and Midland Basin, and relevant technical inputs were recorded for every run in the Jonah Field. Extensive measurements were taken of the wear bands run-over-run to evaluate their effectiveness throughout the trials.

The technical need for protected drill pipe was twofold, effective rock destruction when drilling through hard, abrasive sandstone coupled with the economic need to deliver 2-2.5-mile laterals. For the trials, inspections – including dimensional, visual, Magnetic Particle Inspection (MPI), and Ultrasonic Testing (UT) – were completed on pipe following multiple lateral runs and wells. These data were used to measure and monitor material loss of both the wear bands and drill pipe body and indicated that the wear bands were effectively protecting the drill pipe while wearing at measurable rates. Revolutions, calculated side forces, and lithology were tracked on a run-to-run basis in the Jonah Field to assist with normalizing the measured wear rates and evaluating the effectiveness of the trial wear bands. All this revealed successful runs with the wear bands present.

The value of this improved welding method is that it extends the life of the drill pipe, significantly decreasing the total cost of ownership for operators. Although these trials were limited in scope, a meaningful ROI will be achieved at scale, with all or most of the drill pipe protected with the longest-lasting wear bands. Because the wear bands cost less than 25% of a new joint of pipe and allow the pipe to last up to twice as long, this Return On Investment (ROI) is substantial.
Experimental Setup to Investigate the Permeability of Annular Cement to Fluid Flow
Authors: Opedal N. , Feneuil B. , Wiggen E. , Taghipour A. , Skorpa R.
Published: February 2024

Well integrity issues have been widely studied in the oil and gas sector; however, with storage wells (e.g. towards natural gas, CO2 and H2), new challenges may arise due to the reactivity of the stored fluid in contact with well barrier materials, including migration and leakage of fluids. It is therefore essential to study the reaction of fluids with cement in well conditions to be able to predict the evolution of the cement annulus when exposed to fluids.

We have performed fluid flow experiments through realistic cracks in an annular cement sheath in a downscaled wellbore section. Two different experimental procedures to measure fluid flow have been investigated. The setup consists of a steel casing, cement sheath and surrounding rock. This setup provides a unique possibility to perform pressure cycling experiments to investigate cement sheath integrity and subsequent flow measurement across the 30—cm long cement sheath.

We compare the evolution of the flow rate of both gas (N2) and brine (liquid). Fluid flow testing with N2 and brine provides a reference measurement of the micro annuli permeability for both liquid and gas phases. As nitrogen does not react with cement, it provides a reference flow measurement. This paper reports initial and new results, measuring fluid flow as a function of inner casing pressure of a downscaled wellbore section.
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

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

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

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

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

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

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

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

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

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.
CCS Well Control Impact of CO2 on Drilling Fluid Performance
Authors: Skogestad J. O. , Feneuil B. , N’Gouamba E. , Linga H. , Aasen A. , Skår G. , Roggeband S. M. , Nedrum J. , Helgeland S.
Published: February 2024

By the implementation of carbon capture and storage (CCS) as an important climate action, infill drilling in CO2-rich storage sites will be expected. This implies that actions for handling an influx of CO2 into the drilling fluid must be prepared for. This study aims to close some of the many knowledge gaps when drilling for CO2 storage wells.

To detect and handle CO2 well control incidents, it is necessary to develop software tools that take properly into account the properties of CO2 and drilling fluid and how the mixture of the two performs. To support the development of a such tool, experimental characterization of density, rheology, phase envelope, hydrate formation and drilling fluid stability are performed on drilling fluids mixed with CO2 for relevant pressures and temperatures. Based on these experiments and verified thermodynamic model descriptions, local models for properties of drilling fluid-CO2 mixtures are developed and integrated in an existing drilling software suite. Considerations on similarities and differences with natural gas kicks are made.

Results from the experimental campaigns are presented and analyzed with respect to how the drilling fluid properties are affected by the CO2, e.g.: How does the phase envelope of the drilling fluid-CO2 mixture change with different amounts of CO2, i.e., to which degree is CO2 dissolved in the drilling fluid under different conditions, and when is it a free gas or liquid? What is the impact of CO2 on the drilling fluid-CO2 mixture density? Under which conditions will the constitution of the drilling fluid break down, i.e., loss of rheological properties and risk of weight material sedimentation or drilling fluid component separation?

Furthermore, we consider how these effects can be captured in local constitutive models and integrated in a hydraulic model that can be used for simulating well control incidents. This study provides new insights into drilling fluid-CO2 interaction that are necessary in order to handle risks related to well control incidents when drilling into existing CO2 storage sites. The outcome of this study will help build experimentally verified model algorithms. Implemented in software tools this will enable more accurate simulations of such events than what is available now, and will help in evaluating risks, precautions and operational procedures associated with handling such events.
World's First Demonstration of Hydrogen Blending in Dual-Fuel Engines on a Drilling Rig
Authors: Kernan W. , Lowery J. , van Wissenkerke M. Snijder
Published: February 2024

As part of the global effort to decrease emissions through the use of alternative fuels, the first ever use of hydrogen fuel in a dual-fuel engine on a drilling rig was successfully demonstrated in the Appalachian region. The process of safely managing hydrogen on site is described along with the effects on engine emissions and performance.

Prior to the in-field demonstration, initial testing was performed in a controlled environment to simulate the site conditions and confirm engineering modeling of combustion characteristics. The demonstration consisted of initial testing at 5% hydrogen concentration and concluded with testing at 20% hydrogen. New safety requirements were established with regards to how hydrogen was managed on site. No changes to the drilling program were made in order to validate performance using real-world conditions. The hydrogen was blended into compressed natural gas (CNG) on-site, which provided flexibility to adjust the properties of the fuel mix.

The demonstration successfully proved that the existing dual-fuel engines can support a blend of up to 20% hydrogen without requiring any additional engine development, adjustments to the rig's control system, or hardware modifications. Transient re sponse of the engine was not compromised during load steps, load sheds, or gas shutoffs, even with the maximum hydrogen concentration. Aggressive engine substitution rates were maintained and a negligible change in engine efficiency was observed. Reductions in greenhouse gas (GHG) emissions were observed to be directly correlated to the concentration of hydrogen in the fuel mixture. Although existing infrastructure needs to grow before hydrogen becomes an economically viable fuel for drilling applications, significant investment in the hydrogen industry indicates a future where hydrogen is a widely adopted source of energy. This demonstration represents an important first step to prepare for the hydrogen economy of the future.
The Implementation of Safety-II: Learning from Normal Work in Practice
Authors: Koester Thomas
Published: February 2024

The oil and gas industry has for decades learned about safety from the analysis of failure, adverse events, incidents, and accidents. This approach is called "safety-I". Safety-I has helped the industry reach a plateau of general high levels safety, measured as the absence of incidents, compared to other industries, but there is still room for further and continuous improvements. Researchers in human factors and safety have suggested that safety critical industries, in the future, should not only learn from failure, but also from the normal everyday successful work. This approach is called "safety-II" (Hollnagel et al. 2015), and, in a report from The International Association of Oil & Gas Producers (2022), "learning from normal work". The paper describes the practical implementation and roll-out of safety-II and learning from normal work on board operating drilling rigs.

The learning from normal work project covers 3 phases:

Phase 1: The onboard studies of positive practice, i.e., ethnographic observations of normal daily work and conversations with crew members, e.g., on the drill floor. Phase 2: The development and prototype testing of learning material based on the onboard observations and training of onboard facilitators in the learning team format. Phase 3: The final validation of the learning from normal work concept in a ramp-up case study on a rig starting a new drilling campaign.

More than 160 examples of positive practice from 5 different rigs (2 drillships, 2 jackups and 1 semisubmersibles) were collected in the first phase of the learning from normal work project. The examples illustrate how crews add safety to the process by, e.g., the way they communicate and interact, the way they use technology or the way they plan and discuss their work. The positive examples were filtered and used to generate learning material in the form of learning cards for interactive discussions of safety in learning teams and positive examples to be used in safety meetings and presentations for inspiration as an alternative to failure and incident cases.

One important conclusion from the learning from normal work project is that the crews contribute to the safety of the process through their behavior and small actions in the daily routine work. Thereby, they put many small "safety nets" in place in the system making it resilient and strong.

Looking at positive practice and positive events is new when discussing safety. It changes the narrative and the focus of the discussion from "what to avoid" to "what to do more" and "what to develop and support". This philosophy is based on positive reinforcement as a motivating and driving factor.
Flexible Self-Repairing System: A permanent Isolation Solution in The Gulf of Mexico
Authors: Melo N. , Cardozo J. , Rivera M. Munoz , Antunes Arthur , Taranto Richelle
Published: February 2024

The Gulf of Mexico plays a pivotal role in the United States’ energy landscape, serving as the primary offshore source of oil and gas. It contributes approximately 97% of all oil and gas production on the US Outer Continental Shelf (OCS). Within this dynamic offshore environment, numerous major operators manage a variety of platforms and systems. Notably, a longstanding pioneer in the Gulf region has been at the forefront of technological advancements in the design, construction, and operation of world-class oil and gas production facilities for over four decades. The prominence of being one of the Gulf’s key operators comes with both advantages and challenges that must be addressed as part of the daily operational landscape. Historically, this operator has adhered to its established best practices and remained loyal to proven strategies, which can pose challenges when introducing new products or technologies.

In May 2021, a situation arose when a client contacted a multinational service company, seeking assistance with a well in the production phase located adjacent to the Mississippi Canyon. A case of Sustained Casing Pressure (SCP) emerged in the B-Annulus, necessitating a resolution within an extremely tight timeframe of just 2-3 weeks. In response to this critical situation, our organization was tasked with delivering a solution to remediate the well afflicted by SCP and hydrocarbon (HC) flow issues. Within our extensive technology portfolio, a Flexible Self-Healing Cement (FSHC) system was identified as the ideal solution to ensure well integrity from drilling through abandonment, providing a reliable annular pressure seal and safeguarding against hydrocarbon leaks and SCP at the wellhead. Tailored to meet the client’s unique challenges and specifications, this system was deemed the most suitable choice for the operation. This paper delves into the comprehensive development, execution, evaluation, and post-job analysis of the inaugural application of the Flexible Self-Healing Cement system in the Gulf of Mexico. This innovative system promises to address the pressing challenges posed by SCP and HC flow, further enhancing the operational efficiency and well integrity in this strategically vital region.
Improving Weight-On-Bit and Differential Pressure Measurements with Connection Automation Systems and Pattern Recognition
Authors: Kaya M. , Lanzet B. , Christopher C. , Groh A. , Poludasu S. , Dunbar D.
Published: February 2024

Measuring the values of weight on bit (WOB) and differential pressure (DiffP) through accurate taring is critical for ensuring downhole tool health and creating accurate parameter roadmaps for drilling optimization. Current industry standards for taring rely on the driller to manually select a particular time when these values are zero, which is often imprecise and/or inaccurate. This paper will detail the journey this drilling contractor made to automate the taring process as part of a broader connection automation initiative, how initial solutions challenged organizational assumptions on downhole behaviors, and how a pattern recognition algorithm allowed for better tare consistency and accuracy over existing field procedures.

An initial process automation procedure was designed and implemented in the rig control system (RCS) to manage the connection process, starting with coming out of slips and ending with tagging bottom. As part of this process, the system included a step to consistently tare when the drill bit is one foot off bottom and descending at a constant rate. During field trials, this method gave encouraging results over previous manual tares. Though the result did show improvement over the traditional manual taring method, discrepancies in the relationship between WOB and DiffP eventually led to an improved method of taring which utilizes a novel pattern recognition algorithm. This algorithm detects when the bit tags bottom and establishes a reference hookload (HKLD) at that point. A pattern recognition algorithm was included into the automation sequence replacing the step to tare one foot from bottom.

The initial process automation routine provided consistency to the taring process which was observed during testing. The improvement in consistency revealed inconsistency in WOB tares which was supported by variance in DiffP when WOB was constant. A pattern recognition method was developed to identify when tagging bottom. This algorithm was applied to historical data providing evidence of its benefit to WOB tares. The algorithm was included in an application and then adapted and applied to DiffP tares. The application was run over a historical dataset to qualify its viability. After proving viability, it was exchanged with the taring step in the initial process automation routine and run on live wells. Taring using the pattern-recognition based application presented better results than the manual and initial automation taring methods. The overall operational impacts of each method will be discussed in further detail.

The results of this project challenge underlying assumptions about how taring should be performed and improves overall understanding of the impact of different automation routines. The pattern recognition method discussed in this paper constitutes a novel application which utilizes new technology to improve existing processes.