bluuebunny/crossref_metadata_2025 huggingface dataset:
Mechanical Specific Energy (MSE): Claims and Implications – Facts, Fallacies, and Pitfalls (Part-2)
Authors: Mensa-Wilmot Graham , Samuel Robello
Published: February 2024

Mechanical Specific Energy (MSE) is used extensively in the drilling industry for numerous purposes, most commonly as a strategy for drilling optimization. Additionally, MSE is used for determination of rock hardness, development and assessment of drilling parameters roadmaps, benchmarking, and drilling efficiency calibrations. MSE, in addition to being used for identification and remediation of drilling dysfunctions, is also utilized in completions design optimization for unconventionals. These applications of MSE are important in all drilling operations, regardless of asset class, from exploration through development.

MSE deployment is grounded in several strongly held positions, with associated implications. In Part-1 (SPE 212508) of this critical conversation, which attracted intense industry debate, it was revealed that most MSE claims lack factual validations, and that the assertions had numerous fallacies and pitfalls. These findings, which established limitations and inefficiencies in MSE deployment, are critical for the industry. Most importantly, awareness of MSE shortfalls will ensure development of effective, and verifiable solutions for drilling efficiency improvement. MSE initiatives and claims must be held true, supported by operational objectives, and ratified by physics and drilling mechanics principles.

This follow-up paper identifies additional MSE deficits, with primary focus on its claims. These assertions, as will be discussed include the following – performance benchmarking, drilling efficiency quantification and improvement, identification of performance risks and limiters, recognition, and remediation of drilling dysfunctions – regardless of asset class and/or application type. Fallacies and pitfalls associated with these claims will be identified and analyzed, through appropriate physics-based processes, where the erroneous implications of these claims, will be identified and discussed. In addition to supporting these positions with appropriate field data, a new systematic "Five-Step" process (AIVReC) for discussing dysfunctions will be introduced. It is worth noting that this paper’s positions promote development of appropriate workflows for data analytics and drilling automation processes. These needs cannot be achieved with current MSE positions and claims, because of the numerous fallacies and pitfalls.
A Novel Artificial Intelligence-Based Cement Slurry Design Recommendation System
Authors: Sistla Sai Shravani , Licht Justin , Sadiq Nauman , Drews Tim , Wilberg Dean , Coquilleau Laurent , Manoharan Monisha , Arevalo Yezid , Makarychev-Mikhailov Sergey
Published: February 2024

Cementing is a critical stage in the well construction process, providing zonal isolation, support, and protection for casing. Cement slurry design is a key element in cementing and represents a complex chemical process. Designing slurries with numerous chemical properties is challenging as it must account for often-contradictory requirements. Conventional slurry design relies heavily on using traditional search methods, based on applying numerous filters containing slurry composition, test conditions, additives, etc. This approach is highly ineffective, tedious, and time consuming, and can lead to suboptimal results, because of an engineer’s subjective experience and biases. In this paper we present an artificial intelligence-(AI-)based cement slurry design recommendation system that recommends the most relevant slurry designs based on slurry composition, well conditions, and laboratory test results. The original database contains ~230,000 formulations and ~2 million tests completed since 2018. These data are cleaned, preprocessed, and fed into the recommendation system, which is built in two steps. First, vectorization of all historical slurry records is performed with consistent feature engineering. Key slurry features include slurry composition, well conditions, and laboratory test results. Second, these vectors are used to compute similarity metrics between slurry records applying AI-based algorithms, such as clustering, exact, and approximate nearest-neighbor methods. In the inference phase, the system uses the computed similarity metrics to recommend the most relevant slurries for a set of design requirements. The AI-based system is data-driven and objectively recommends the most relevant slurries for a set of design requirements, from the database. A comparative study of the tested AI algorithms and their corresponding outcomes is presented. Specific evaluation metrics are proposed to evaluate the recommendation results. The recommended slurries are visualized in both tabular and graphical forms, for user-friendly analysis. In addition, several examples are provided that demonstrate how this innovative approach improves the slurry design methodology. The proposed approach enables retrieval of the relevant slurry candidates from a huge database in seconds, compared to performing manual search and analysis, which can take hours. The recommended slurries form a solid foundation for later stages of the slurry design process. Furthermore, smart selection of slurries saves many hours of expensive laboratory testing.
Achieving ISCWSA MWD+IFR1 Tool Codes Without Airborne Magnetic Surveys
Authors: Paynter Ryan , Paré Andrew , Crookston Glenna , Berarducci Alec
Published: February 2024

Accurate wellbore placement and collision avoidance are increasingly important in today's tightly spaced horizontal wells and congested fields. Modern well plans incorporate hydraulic fracture geometry, reservoir characteristics, and other factors to maximize reservoir extraction while minimizing drilling costs and safety risks. Directional surveys that have minimal uncertainty are crucial to drilling the optimized well plan. This work enables more accurate directional surveys and wellbore placement through site-specific high accuracy magnetic models.

Under the Industry Steering Committee on Wellbore Survey Accuracy (ISCWSA) error model, the use of In-Field geomagnetic Referencing (IFR) dramatically reduces some of the largest sources of error in wellbore location. Unfortunately, IFR can be expensive or out of reach for smaller or less mature basins because of the high cost of flying or purchasing high-resolution aeromagnetic surveys. An economic and timely alternative has been developed, strategically taking ground magnetic measurements at sites along the wellbore(s) with absolute instruments, combined with a high-definition global magnetic model to produce IFR at the pad scale.

This method was tested in the Denver-Julesburg Basin in Colorado. A small survey team collected ground magnetic measurements over a typical pad design in one day. The data was then processed and combined with a high-definition global magnetic model to produce IFR corrections locally for the pad. This study demonstrates that the procedure reduces the horizontal wellbore position uncertainty by 46% for the study area and more generally from 15 to 50 percent when compared to standard MWD (Measurement While Drilling) survey technology. Furthermore, this method was compared to a typical IFR model created from airborne measurements. We found that the results from the comparison agreed within tolerance to the IFR model and validated the use for IFR corrections at a pad scale. This technique improves confidence in wellbore placement, mitigates collision risks, improves reservoir drainage, and helps to maximize production.

Much work on the construction of IFR magnetic models from airborne total field data for large areas has been done. This work is novel in that it describes the construction of an IFR magnetic model from a small number of ground magnetic vector measurements, in combination with a high-definition global magnetic model for a small area. This innovative approach makes IFR corrections significantly more accessible to drilling programs with shorter timelines, fewer wells, and smaller budgets.
Comparing Drilling Anomaly Prediction by Purely Data-Driven and Hybrid Analysis Methods - Case Study of Utah FORGE Geothermal Wells
Authors: Montes Abraham C. , Ashok Pradeepkumar , van Oort Eric
Published: February 2024

Automatic prediction of drilling incidents can be conducted through either a purely data-driven approach or a hybrid approach. In the first approach, the variable space is typically limited to surface measurements and downhole sensor data, while in the second approach, the variable space is expanded to include information from physics-based models. This paper analyzes the additional value of incorporating physics-based information to predict drilling incidents such as stuck pipe, illustrated using data from the Utah FORGE geothermal wells.

In our study, we trained three anomaly detection models with two distinct variables spaces. In the first one, we considered the real-time signals only, while in the second one, we included physics-based information derived from cuttings-transport, tortuosity, and torque-and-drag models. We selected three models that showed promising results in recent studies and represent the taxonomy of machine-learning-based anomaly detection algorithms. Specifically, we utilized recurrent neural networks, autoencoders, and clustering. Finally, a comparison between the two approaches was performed in terms of the fidelity of the warnings they generated.

We observed that the inclusion of physics-based information is key to improving the performance of models for predicting drilling incidents. Specifically, we noted a reduction in the number of false alarms, which, in turn, increases the reliability of the models. In addition, we found that physics information can guide the selection of prediction time windows when drilling anomalies develop, thereby eliminating bias in the models' construction. Finally, we observed that some drilling anomalies, which were previously believed to occur suddenly with little warning, can, in fact, be predicted in a timely manner with hybrid models. These observations demonstrate that the use of hybrid models can significantly increase the performance of drilling anomaly predictions, providing sufficient forewarning time for their prevention and associated NPT avoidance.

State-of-the-art methods that implement purely data-driven and hybrid approaches have individually demonstrated high accuracy in predicting incidents on specific datasets. However, no previous comparative study has been conducted to analyze the value of incorporating physics-based information. This paper is the first to perform such an analysis for models aiming at the early detection of drilling anomalies. The results from this study provide valuable guidance for future NPT avoidance in drilling operations.
Real-Time Automated Pore Pressure and Wellbore Stability Updates in a Digital Twin, Using Smart Agents and Log Predictions Ahead of Bit, Example from Norwegian Continental Shelf
Authors: Lothe A. E. , Roli O. -A. , Skogestad J. O. , Cerasi P. , Boukili M. , Kristiansen T. G. , Grøver A. , Wølstad-Knudsen S.
Published: February 2024

The main objective in this work was to develop and test automated pore pressure and wellbore stability predictions ahead of bit using a digital twin. The new automated real-time workflow, with three smart agents for pore pressure, mudweight and well pressure was tested on historical data and real-time drilling campaigns for one exploration well and several production wells in the North Sea and offshore Mid-Norway. A digital workflow is set up from pre-drill 3D basin scale pore pressure modelling using a stochastic Monte-Carlo approach, including an automated update of pressure prognosis while drilling using sonic or resistivity data. Additionally, the innovative approach will also reduce the uncertainty in the predicted mud-weight window ahead of the bit. Three new smart agents have been implemented in a real-time data platform for drilling; one for pore pressure prediction, one for mudweight real-time calculations and one for well pressure real-time predictions.

The new automated workflow has been tested on several wells, either in real-time, or on historical data as playback. Both pressure real-time updates using sonic log (for exploration well) and resistivity data (for production well) have been tested with very good results, especially when filters on the raw log data are used, removing artefacts in input data, effect of well inclinations, lithologies etc. In addition, the real-time Equivalent Circulating Density (ECD) prediction has been compared with downhole ECD measurements. Digital twin using playback data from a well, offshore Mid-Norway has been carried out with automated correction and smoothing of the calculated pore pressure from resistivity log. The new automated workflow will contribute to increase the efficiency of drilling operations subject to narrow pressure margins and uncertain reservoir pressure, by providing a quantitative and adaptive automated workflow to support the drillers/rig crews.

The new automated workflow is presented for both exploration and production wells and the workflow can contribute to more cost effective and safer operations. The methodology can in the future be combined with machine learning.
Experimental Visualization of the Effect of Flow Rate on Downhole Drilling Vibration
Authors: Maitra E. K. , Al Dushaishi M. F.
Published: February 2024

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

During well planning, specifying the separation that must be maintained from offset wellbores is critical to ensuring safe operations. Recent efforts on API RP 78, an upcoming recommended practice for wellbore placement, have provided guidelines for calculating safe separation distances and engineering considerations for those calculations. A major milestone was the publication of a separation rule (Sawaryn, et al. 2019) standardizing a formula for separation factor (SF), which in turn defines the minimum allowable separation distance (MASD) between two wellbores and the allowable deviation from plan (ADP) for a wellbore being drilled. One element of this formula, σpa, describes the accuracy with which a future wellpath can be predicted. Prior guidance provides a suggested value for σpa (1.6ft or 0.5m at 1-sigma) based on heuristics. A more rigorous approach for estimating this value is presented, where the design of the drilling program can be considered.

A framework is proposed for modeling deviation from a projected path using a planned trajectory, bottom hole assembly (BHA) properties, and survey practices. The method identifies where a deviation is detected through survey measurements and estimates a planned recovery operation. Equations are provided for estimating the distance from plan at deviation detection along with the maximum expected deviation during recovery. Common drilling scenarios are analyzed for sensitivity to operational parameters such as survey course length, sensor offset, toolface control, and BHA performance. The impact of varying σpa is explored across prototypical collision avoidance cases. A discussion of the relationships between the σpa value and the common collision avoidance calculations such as SF, MASD, and ADP is included along with considerations for the design of a risk management policy.

Survey course length, survey sensor offset and uncertainty in directional performance are all shown to have a significant impact on the potential maximum deviation from plan. An additional factor considered is the aggressiveness expected when performing recovery operations. An analysis of common drilling scenarios suggests the previously provided guidance of 1.6ft at 1-sigma appears suitable for cases where the directional behavior of the BHA is well characterized and the combination of course length and survey sensor offset is kept to 150ft or less. Longer survey course lengths, larger sensor offsets, or uncertainty in directional performance of the BHA can produce larger σpa values, in some scenarios causing a significant impact on the MASD and ADP.

Previous work has called attention to the uncertainty in drilling to a projection, but up to now there has not been a rigorous method for estimating that quantity. With the methods outlined in this paper well planners and drilling engineers can make more informed decisions on how to ensure safe separation practices in their own operations.
Interoperability for Drilling Process Automation
Authors: Kuilenburg R. Van , Isbell M. , Behounek M. , Macpherson J. , Schaefer S. , Fox T. , Pirovolou D.
Published: February 2024

Drilling automation and remote operations are driving advisory systems to provide a safe operating environment, protect the wellbore, and optimize efficiency at the wellsite. These interoperable systems deliver guidance to control systems, for example set points and limits for drilling parameters. The Drilling and Wells Interoperability Standard Industry Group (D-WIS) under the SPE Drilling Systems Automation Technical Section (DSATS) wants to accelerate interoperable system implementation by outlining a compelling value case.

The adoption of drilling operation automation systems is increasing operational efficiency and opening new opportunities to manage drilling with advisory systems. These systems are the focus of efforts in interoperability (i.e., plug-and-play functionality) to remove data communication obstacles and allow the implementation of the next generation of advisory and process control technology. This paper describes the technology focus, status, and impact of the current industry efforts and organizations contributing to interoperable systems regarding the core system components and standardization needs. The value case is made for an interoperability standard suitable for large scale industry deployment.

The current industry state reveals custom-made supplier solutions continuing to expand and evolve with limited applicability due to a bespoke approach. The authors observe and contrast this method with an interoperable system approach to make the value case in terms of easier and faster implementation and scalability, better reliability and access to data, and lower development and operations cost, resulting in a higher overall value. A comparison of the two competing scenarios along with past industry efforts toward standardization clarifies how to best realize the vision of safely and efficiently sharing information and facilitating drilling operations. Collaborative efforts between industry organizations also help address areas of overlap and gaps related to interoperability and creation of a standard. The conclusions outline the minimum requirements of a focused industry effort to deliver an implementation-ready system. System adoption is accelerated by creating deliverables fit for roadmaps and specific collaboration points.

The paper examines the effectiveness of current interoperable system efforts. It describes and demonstrates industry influencing work towards interoperable drilling systems and builds on a collection of industry work beyond Sadlier and Laing 2011, and Macpherson et al. 2013.
The Value of Process and Application Consistency in Drilling Automation
Authors: Auld S. , Whitlow Z. , Hopwood F. , Kern S. , Willerth M.
Published: February 2024

The drilling industry has undergone significant changes in recent years, leading to increased efficiency, lower costs, and reduced emissions per production unit. As unconventional well construction complexity continues to increase, the next wave of innovation lies in process automation, offering improved consistency and the opportunity to enhance drilling engineering designs.

Effectively automating drilling a stand while minimizing human variability requires a scalable control system, providing adaptability, seamless implementation, and improved operational outcomes. The system requires high- and low-level process control components to effectively control rig machinery within the bounds of the machine limit controls. By using automation sequences while engaging and disengaging the drill bit, operational states such as breakover, optimal weight on bit (WOB), steady state hookload, and zeroing become easier to distinguish.

Through consistent implementation of process automation in drilling operations, the impact on operational outcomes became evident. Analysis of bit disengagement in a series of automatically drilled stands in the lateral revealed a consistent breakover range of 18 to 22 ft. This is particularly noteworthy as breakover is typically more challenging to identify and prone to variability in manual operations.

Zeroing WOB in the lateral at a predetermined drilling interval is common practice to calibrate the drilling system, and procedures provided by the operator are often conservative due to human variability resulting in slower process execution. While drilling automated stands in a lateral, it was determined the lowering sequence of the process could be reduced by half to effectively zero the WOB and differential pressure, reducing invisible lost time.

Not all invisible lost time and variability is human related; variability due to equipment design was reduced. Torquing drillpipe connections is essential to drilling a well. Development of high spec automated floor wrenches improved make-up connection torque accuracy and consistency primarily associated with fundamental tool design. These improvements led to a connection integrity paradigm shift, reducing manual tong usage by 99%, effectively eliminating the need for high torque tongs at a wellsite, leading to improved tripping time and safety.

As drilling automation continues to evolve, the outcomes obtained through consistent process execution provide valuable insights. Additionally, this contributes to a decrease in emissions per unit of hydrocarbon production. Consistency through automation reveals new avenues for in-depth technical discussions on achieving safe and efficient drilling of progressively complex wells.
The Insulated Drill Pipe - Field Experience and Thermal Model Validation
Authors: Vetsak A. , Besoiu C. , Zatonski V. , Torre A. , Hodder M. , Toews M.
Published: February 2024

To drill deeper and hotter wells, such as for high temperature high pressure (HPHT) oil and gas or geothermal applications, proper management of bottomhole temperatures is critical to ensure survival of electronic tools and to improve drilling performance. The paper introduces a new type of the Insulated Drill Pipe (the "IDP") which minimizes heat transfer from the annulus into the drill pipe, to deliver drilling fluid to the bottomhole assembly (BHA) with substantially cooler circulating temperature than using the non-insulated drill pipe.

An iterative design process was followed to develop a robust and cost-effective insulating material that can be applied to the inside and outside of the standard non-insulated drill pipe. After testing a series of different insulating materials in the lab and in the field as prototypes, a new coating system was chosen for the first generation of the IDP. Concurrently, a detailed thermal model was developed to estimate the expected cooling effect of the IDP.

A full IDP string was manufactured in 2022 and was subsequently used in three field trials: a geothermal test well in New Mexico, the USA DOE FORGE project in Utah, and a US-based shale well. During field trials, mud inlet and outlet temperatures and measurement while drilling (MWD) temperatures were monitored. In some cases, mud chillers were used at the surface to decrease the inlet mud temperature. Both real-time and recorded MWD temperatures were obtained. At FORGE, recorded circulating temperatures at the MWD were reduced by up to 42 °C (75 °F), from 107 °C (225 °F) to 65 °C (150 °F) in formation temperatures exceeding 150 °C (300 °F). Analysis of wear and robustness of the insulating material were inspected on all joints of drill pipe and damage in vertical and deviated wells was minimal. High normal forces and friction in a horizontal well did result in significant damage to the coating which can be remedied through improved coating design. The thermal model was validated with the measured data and used to accurately predict the performance of IDP in future runs.

This is the first extended field trial of the IDP, and the results demonstrate the value of the IDP to reduce mud temperatures downhole. The IDP allows for improved cooling of the BHA components, particularly electronics, and extends the operating window of existing MWD, electronic equipment and other BHA tools to deeper and hotter environments. This is critical for the HPHT wells and for deep and hot geothermal wells, reducing the cost of the instrumented BHAs for these wells, while improving downhole tool reliability, and reducing a frequency of tripping operations due to downhole failures. The developed thermal model can also provide maximal connection times by estimating the rate of borehole heating while rig pumps are off.
To What Extent Can the Notion of an Effective Length Be Reliable to Assess the BHA Lateral Behavior?
Authors: Mahjoub M. , Dao N. -H. , Nguyen K. -L. , Menand S.
Published: February 2024

Many models in the industry use the notion of an effective length to make predictions about the bottom hole assembly (BHA), whether for its directional behavior or its lateral vibration tendency. A given criteria is chosen to cut the drill string at a certain distance from the bit and use only that part for the computations. In this paper, this cutting distance is referred to as the effective length. Though computationally efficient, and thus providing fast real-time predictions, there is no consensus on what criteria should be chosen, nor a "bulletproof recipe" on how to compute that length. Miscalculating this effective length, especially for vibration mitigation purposes, can lead to suboptimal rotation speed selection, potentially causing failure.

To address this challenge, different choices of effective length computations are compared in terms of BHA yield rate prediction (build/drop and turn rate). Past a given distance from the bit, the computed side force and tilt at the bit are nearly identical, meaning that any element very far from the bit is negligible in the static calculation. However, studying lateral vibrations is more complex especially at low inclinations or in horizontal wells with high weight on bit (WOB) where the drill string can move more freely with snaking and whirling motions. A nonlinear time-domain model is utilized to evaluate the propagation of lateral vibrations up the string. A sensitivity analysis was then conducted on several BHA types and lengths, considering different boundary conditions in vertical and horizontal wells.

Directional models are found to be reasonably unsensitive to the choice of the effective length because they are based on steady-state computations, but the same cannot be stated for dynamics. This study developed a more robust approach to estimate properly the effective length for lateral vibrations, an essential for BHA resonance. The theoretical predictions of critical speeds were compared to time-domain simulations, which take into account the nonlinearities related to contact and friction forces. Spectral analysis of the results helped identify the main sources of vibration, whether it comes from BHA mass imbalance, drill string-wellbore interactions, or other sources. This combination between frequency- and time-based analyses is used to validate our choice of the effective length.

Many models, from steady state to dynamics with both frequency and time domain analysis, are used to approach the effective length problem from various perspectives. This study aims to compensate the lack of in-depth analysis on this important subject. It shows the importance to understand the strengths and limits of frequency-based models compared to the more complex time-domain modeling.
Settled Barite as a Potential Barrier Material: A Field Case Study
Authors: N’gouamba E. , Bhuiyan H. , Stroisz A. M. , Taghipour A. , Skorpa R.
Published: February 2024

During plugging and abandonment (P&A), sedimented and compacted barite adds considerable complexity to the plugging operation. Casing cut and pull is alone responsible for approximately 50% of the cost to establish a formation-formation barrier. However, if the settled barite in the annulus can be used as an additional barrier element, P&A operations can be simplified, and the cost reduced. With this in mind, it is therefore necessary to investigate the sealing and mechanical properties of settled barite. In this study, settled barite from a field on the Norwegian Continental Shelf is investigated to understand the mechanical and sealing properties of the settled and compacted barite from the wellbore and to compare them with cement properties. Strength and ultrasonic measurements are carried out on cored samples to assess their mechanical properties. Computed Tomography scans give an overview of the sample’s texture, and the Scanning electron microscopy provides insight on the microstructure and changes in the chemical composition of the barite from the oil well. In addition, the cohesion (or resistance to mobilisation) of barite powder is assessed by direct shear strength under various loads using a rheo-powder cell. We start by measuring the mechanical properties of settled and compacted barite, which are relatively similar in all samples. Then, compared with typical cement G, settled barite presents low stiffness and mechanical strength. Finally, we compared the mechanical properties of settled barite powders from the field with those of unused sample from the laboratory. In both cases, the barite powder exhibits low flowability, i.e., it is extremely difficult to mobilize, and this increases with humidity. In this paper, new results on the assessment of settled barite as a barrier material are reported through various mechanical, ultrasonic, and imaging tests of a realistic settled and compacted barite from an oil field and compared to an oil well cement. In this case, we observed that the settled barite has poor mechanical properties for potential use as an additional barrier element. This could be link to the original formulation of the drilling fluids used and the conditions of use in the well.
Mud-Gas Separator Analysis: A Comprehensive Review of Sizing, Design Criteria, and Industry Standards
Authors: Tetteh D. A. , Salehi S. , Ghalambor A. , Konate N.
Published: February 2024

The Mud-Gas Separator (MGS) is a critical component in well control for handling gas kicks. It is the primary device for separating liquid-gas mixtures in most well control events. Poor separator designs and inefficient separation of gases from liquids in the MGS have resulted in the loss of lives and equipment and adverse environmental effects. Thus, the safe and efficient separation of gases from gas-cut drilling fluids in the MGS is vital. The design and operational efficiency of the MGS depend on certain key elements in its sizing, such as the vent line length and diameter, vessel internal diameter, hydrostatic head of the mud seal, and the vent line back pressure, amongst others. These design considerations and the industrial standards and regulations governing them are hitherto not fully understood. As a result, there is an associated risk in the operation of the MGS.

This paper aims to comprehensively review and analyze key sizing and design considerations for the Mud Gas Separator for both Conventional and Managed Pressure Drilling Operations. Furthermore, industry standards, best practices, guidelines, and regulations on MGS design and operations are also reviewed.

This study uses two primary methodologies: an extensive literature review and a stakeholder engagement consultation to meet the stipulated objectives. The results indicate that the sizing and design of MGS depend on various factors such as well depth, pressure and temperature regimes, formation fluid, and completion fluid systems. The study's outcomes also indicate that existing industry standards and regulations provide sufficient guidelines for various sizing and design considerations. The study also presents an analysis of existing industry recommendations on MGS design and sizing for special wellbore conditions, formation properties, and unconventional drilling applications like managed pressure drilling (MPD).

The study provides further understanding of the MGS sizing and design from industry stakeholders’ perspective to minimize well-control risks associated with MGS.
Raising the Bar: Why an Industrial Standard for Testing Hydraulic Sealability of Well Abandonment Materials in Laboratory is Essential for Well Integrity
Authors: Skorpa R. , Opedal N. , Khalifeh M. , Moreira P.
Published: February 2024

Advances in the properties of OPC and new materials (i.e., mechanical strength, rheological properties, etc.) have shifted the R&D focus towards sealing capability of plugging materials at interfaces between the material and its adjacent medium. The objective of this paper is to outline the importance of new standards for studying hydraulic sealability of barrier materials, with emphasis on interface analysis. This work reviews different procedures used to study hydraulic sealability of barrier materials. Reviewing current standards and procedures for testing and qualifying zonal isolation materials indicates that the focus is mainly on the bulk properties of cement, such as expansion/shrinkage, permeability, and mechanical strength. The benefits of these standards are to provide reproducible results, consistent testing procedures and prevent misunderstandings about behavior of hardened cement in laboratory and field operations. However, interfaces are complex and cannot be tested with current standards, meaning that mechanical properties alone cannot indicate hydraulic sealability. The review process also includes non-setting materials further indicating the need for updated standards.

Per today, there is published work on sealability testing on the barrier material interfaces, either towards the surrounding rock or towards the casing. This is of particular importance due to more emerging well types such as CCS, hydrogen storage, geothermal wells, and purpose based well integrity and plug and abandonment. A thorough review of sealability test setups indicates that different research groups have designed setups with similar features, but with variations on scale dimensions, testing protocol and so on. This, in combination with the availability of modern measurement technologies, offers the possibility of enhanced understanding of barrier sealability. As no standards currently describe a uniform testing procedure, direct comparison of results is thus inaccurate, putting the reproducibility and reliability of analyses at risk. Our observation shows that possible considerations for standardization include understanding the effect of dimensional scales, the sequence in the procedure, the duration of testing, the type of casing steel or rock, and the type of invasion fluid besides the amount of released heat of setting material. Therefore, it is highly beneficial that current standards are updated to include sealability analysis, and updates for new and alternative materials, such as geopolymers, settled barite, and metal alloys.
Computational Design of an Optimal Landing String Profile for Operations in Harsh Environments
Authors: Abnave Vivek , Shenoy Mahesh
Published: February 2024

The subsea test tree is a singular subsea safety solution for well test and cleanup operations from any floating rig. The test tree provides wellbore access, dual-barrier well control, and a reliable, fast-acting means to shut in a well and disconnect, in the event of an emergency. Currently, the ability to run and operate the string is severely dependent on the weather conditions due to its influence on the riser flex joint angles. Therefore, the maximum allowable flex joint angle places severe limitations on the weather operating windows. This study outlines the use of computational analysis to formulate the design changes that are needed to extend the current capabilities of the latch mechanism that secures the landing string inside the Blow Out Preventer (BOP). Simulations are conducted using a design of experiments methodology to enhance the asset’s bending ratings. A parametric analysis is conducted and components with geometric features that can potentially impede the sliding motion of the landing string, such as the latch skirt are explicitly modeled.

The finite element analysis (FEA) technique is used to identify the critical components, which can be further optimized to determine the geometric profile, which eventually ensures that the string passes through the riser flex joint without shouldering out at the BOP annular pockets with minimal push or pull force. The study extends the capability of the Subsea Landing String for use with higher flex joint angles and establishes the structural and functional load limits for the different operational scenarios. The solution highlights the importance of using computations in design as a viable alternative to expensive and time consuming experiments, especially when solving complex problems.
The New Era of Deep-Water Drilling Through Integrated Automation Technologies: A Gulf of Mexico Case Study
Authors: Lazzari A. , Iolli F. , Leo G. , Bianchi L. , Sharma N. , Guglielmo C. , Yost T. , Ferrari F.
Published: February 2024

In today's ever-changing and competitive environment, oil and gas industry is quickly moving towards integrated technologies as a founding pillar of any business strategy able to meet the trilemma of the growing energy demand together with the need of an equitable supply and its environmental sustainability.

Deep water drilling technologies are universally recognized among the front runner along this road map, coming from a long journey of trials and errors and capable only in the recent years to move close to the full potential made by the integration, completely machine controlled, of multiple rig equipment.

This paper describes one among the first experience made in the industry of such process control automation set up on the 7th generation drilling ship Saipem Santorini in Gulf of Mexico over the years 2022 and 2023.

Results achieved clearly demonstrate a tangible enhancement of the work safety, as the human/machine interface is lowered by near the 50% along the whole well construction process, as well as the drilling and completion performance went beyond the 10% of global well time reduction, just as a starting point.

This first experience has been documented over a collaborative one-year period through advanced KPI monitoring and systematic approach used for installation, training, remote support and data analytics that illustrates a proven path to success which is going to be reiterated soon up to a level of a new standard for deep water drilling.
Addressing the Energy Trilemma: Offshore Drilling Rig Decarbonization
Authors: Falck F.
Published: February 2024

Offshore drilling rigs play a crucial role in global energy production, particularly in the extraction of oil and gas resources. However, the industry's environmental impact has raised concerns about the need for energy efficiency and decarbonization in offshore operations. This paper aims to explore the challenges and opportunities associated with improving energy efficiency and decarbonizing offshore drilling rigs.

The first part of the paper provides an overview of the Energy Trilemma (Sustainability, Security and Equity) followed by an introduction on the importance of data collection and analysis necessary to monitor energy consumption patterns and carbon emissions associated with offshore drilling rigs. It highlights the significant energy requirements for drilling and mobilization activities along with the corresponding greenhouse gas emissions. These emissions contribute to climate change and environmental degradation, necessitating clear actions for reducing carbon footprints.

The paper highlights the economic and environmental benefits associated with energy efficiency and decarbonization efforts. It emphasizes the potential cost savings resulting from reduced energy consumption and the avoidance of carbon-related taxes or penalties. Furthermore, it reviews a 360-degree approach to Offshore Drilling Rig Decarbonization embedding it into operations, operator-contractor engagements, and technical advances. It also emphasizes the positive impact of such initiatives on reducing greenhouse gas emissions, promoting sustainability, and improving the industry's environmental stewardship.

Next, the paper discusses the potential strategies for enhancing energy efficiency on offshore drilling rigs. It examines advancements in optimized rig design, energy efficiency upgrades, energy storage systems and sustainable behavior enhancements. Additionally, it explores the adoption of low-carbon fuels and electrification of offshore rigs. The proven and expected benefits, challenges, and implementation considerations of these strategies are examined.

In conclusion, achieving energy efficiency and decarbonization on offshore drilling rigs is essential for addressing the Energy Trilemma while it is necessary that the drilling contractor and operator work closely together in operating the business in a way that meets economic, social, and environmental needs of the present without compromising the ability of future generations to meet their own needs. By embracing innovative technologies, optimizing operations, and transitioning towards cleaner energy sources, offshore drilling rigs can significantly reduce their carbon footprints while ensuring a sustainable and responsible future for the industry.
The Effect of Drilling Fluid Contamination on the Properties of Granite-Based Geopolymers at Elevated Temperature
Authors: Khalili P. , Khalifeh M. , Saasen A.
Published: February 2024

Granite-based geopolymers have shown great potential as viable and sustainable alternatives to fully replace OPC. This article shows the impact of drilling fluid contamination (both water-based and oil-based) on the rheological and mechanical properties of such a geopolymer. The mechanisms involved in contamination are also explored. The maximum contamination intake before geopolymers lose most of their strength is investigated. Optimized granite-based geopolymer is mixed with varying volumes of a typical water-based drilling fluid (5% and 10%). The resulting mixture is cured under bottom hole static temperatures (BHST) of 70℃ and 13.79 MPa pressure to simulate production casing conditions. Compressive and tensile strengths of the cured contaminated geopolymer are measured after 1, 3, and 7 days. The early strength is evaluated using the Ultrasonic Cement Analyzer (UCA). The impact of the drilling fluid on the geopolymer's microstructure is analyzed using Scanning Electron Microscopy (SEM). The results show that the geopolymer is more sensitive to the Water-Based Mud (WBM), and slurry does not develop strength after 1 day if contaminated with higher than 10% WBM. This behavior is due to geopolymerization reaction in which water remains in the system, unlike the consumption of water in OPC due to hydration. Particle sedimentation is also increased as more contamination is introduced into the geopolymer. SEM images show that after contamination with OBM, geopolymer slurry becomes an oil in water emulsion which leaves dispersed oil in pores throughout the sample after the setting phase.