bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Method for Dimensional Measurement of Oilfield Tubulars to Optimize Operations and Minimize Risk Factors
Authors: Rodriguez Andres , Logan Kevin , Nickles James , Carlson Greg
Published: March 2022

Technological advances in the nondestructive evaluation of Oil Country Tubular Goods (OCTG) have brought about enhanced methods to minimize risk factors associated with the drilling or transport of oil and natural gas. This paper focuses on a multidimensional, nondestructive testing (NDT) inspection and measurement package combining wall thickness and outer diameter (OD) measurement data into a single inspection report per tubular. This method of dimensional measurement is performed on the front end of a project, providing end users with numerous benefits from a cost and time perspective, as well as the critical data needed to optimize operations.

The package provides high-resolution inspection data for the manufacturer or end user, yielding higher precision burst and collapse strength predictions than previously available. Other benefits of this method include optimization of material placement in casing string design, estimation of cementing fluid volume, and downhole tool clearances among other applications. Confidence and safety levels of burst and collapse ratings are of particular interest to drilling engineers.

The wall thickness variations and tubular eccentricity are measured using an automated, nondestructive ultrasonic testing system, utilizing compression wave transducers. The OD measurement is acquired using an automated, nondestructive laser-based testing system. Laser-based testing uses two laser-scan micrometers positioned horizontal to the tubular and 180° apart (Fig. 1). Each laser measures the distance between the tubular and the receiver. These two measurements are combined to calculate the tubular OD.

The level of accuracy provided by this technology continues to push the industry forward with higher quality tubulars ranging from the mills to end users.
Drilling Parameter Optimization in Real-Time
Authors: Oedegaard Sven Inge , Helgeland Stig , Mayani Maryam Gholami , Trebler Andrey , Bjorkevoll Knut Steinar , Skogestad Jan Ole , Lien Morten , Weltzin Tore , Rudshaug Bjørn
Published: March 2022

The objective of this paper is to demonstrate how drilling parameter optimization in real-time provides a drilling team with an Edge-system that can continuously improve performance and avoid problems without the need for subject-matter experts.

An Edge-system based on cloud technology with Model based reasoning in Artificial Intelligence (AI) is made to give real-time and forward advice for operational parameters, see (Lahlou et al, 2021) for description. The key enabler for such system is "automatic" auto-calibration of models to be used for multiple forward-looking and what-if to find optimal drilling parameters within the well envelope ahead. A simplified configuration has been made so that the rig-team can operate and maintain the system without the need for subject matter experts. "Automatic" Auto-calibration at stable conditions and/or during ramping conditions removes the need for such experts.

Results from testing of the Edge-system on multiple wells from several operators will be presented both related to automatic auto-calibration of real-time prediction models and for optimization of drilling parameters. As expected, a major challenge has been to design a calibration algorithm that improves accuracy of calculations without being kicked out by any data quality issues, and without masking upcoming actual anomalies like kicks, losses and issues related to hole cleaning. This challenge has been approached by using a combination of time-delayed robust calibration methods and testing on a comprehensive set of data from diverse operations.
DDNet: A Multi-Agent Decision Making and Evaluation in Drilling with Looking-Ahead Simulation
Authors: Yu Yingwei , Jeong Cheolkyun , Chen Wei , Shen Yuelin , Vesselinov Velizar , Chambon Sylvain
Published: March 2022

Operators drilling a directional well may suffer the uncertainties from the downhole environment, the equipment, and the human decision-making process. We proposed a method to evaluate steering decisions of multiple reinforcement learning agents by calculating the estimated total future reward (ETR) through a validation agent using a simulator. The final decision would be chosen as the one with the maximum total reward among the multi-agent decisions. The multi-agent approach stabilizes the final decision-making for directional drilling and results in a higher success rate and better overall steering performance.

In our previous work (Yu et. al, 2021), a single agent was trained to make decisions for directional drilling through the deep reinforcement learning framework. To improve the stability of the decisions, we extend the single-agent approach to this multi-agent framework including a working environment and a validation environment. The system includes a working environment that includes a pool of working agents. The working environment represents the current physical drilling environment (e.g., rig state, geology, bit location, and planned trajectory). In addition, a validation agent is working in a validation environment using a hole propagation simulator for projecting the ETR.

When the system is in action, the working agents receive inputs such as surveys and planned information in the working environment and each of them makes their own decisions. Their decisions, as action proposals, are passed to the validation agent while the validation environment synchronizes the state from the working environment. The validation agent then carries out each action proposal in the virtual environment through the simulator and continues drilling to the target multiple times given a variety of formation priors. An average score of ETRs is then calculated for each action proposal. As a result, the action proposal with the maximum average score wins the competition and goes back to the working environment for execution.

The multi-agent framework could optimize and stabilize the sequence of decisions while minimizing uncertainties. Our validation results demonstrate that the total rewards were successfully improved than the single-agent decision-making.
Quantification of Our Carbon Footprint While Drilling
Authors: Johnson Ashley , Mäkinen Anna , Fahim Syed , Arevalo Yezid
Published: March 2022

Reducing our operating carbon dioxide emissions is a critical step in mitigating the impact of our well construction operations. To demonstrate a quantifiable benefit, we need a starting point. We need to measure our current emissions and identify the main drivers of the footprint. From there, we can identify best practices to reduce environmental impact and quantify how changing our drilling systems can lower CO2 generation.

Analyzing the data available from two modern land rigs we have measured the CO2 released for drilling different wells in different basins. We have also segmented the emissions by the rig systems using the power they consume. We show that the mud pumps are the biggest culprit for the CO2 release. The top drive draws less power; and while the draw works have a very high-power capacity, they only draw this for a very short period so overall their footprint is much less significant.

In order to make this work relevant for more than a small number of high specification modern rigs, we have built and validated an emissions model, thanks to which, we can calculate the CO2 released from measured drilling parameters. As such, we can generate, in real time, a carbon emissions log quantifying the footprint and the contributions of the major systems on any rig where we have access to these surface data.

Using the same model, integrated with our well planning processes, we can accurately predict the footprint from a well construction scenario and quantify the benefits which changes to the BHA, the drilling practices or the well design would bring. In the same manner, based solely on the drilling data, the comparison of the environmental impact of all of our drilling operations with a high level of granularity is enabled. With data, which is already available, this lets us identify opportunities to reduce emissions and less efficient operations rapidly at a global scale.
Applying Digitalization for Energy Efficiency Insight and Advancing It Towards Carbon Emission Reduction Targets
Authors: Puskarskij Konstantin , Loftager Rune , Hoffner Jan , Haastrup Peter , Kugendran Sajith , Moody James
Published: March 2022

This paper details the successful development and application of digital solutions, providing insight into fuel and energy consumption onboard offshore drilling rigs. Technical details behind the solutions are outlined in the paper, as well as how they can be applied to pursue industry sustainability goals by reducing the environmental footprint from offshore drilling operations.

Different methods for providing the insight were applied; utilizing a precise measurement of fuel consumption or, alternatively, using diesel generators’ performance, and advanced data analytics to determine the energy consumption of offshore drilling rig equipment and systems. Where feasible, one of these two methods has successfully been rolled out on offshore drilling rigs and confirmed to deliver very close results with high accuracy.

Such information is used to provide fleet-wide monitoring of fuel consumption, Green House Gas (GHG) emissions, and how it is compared against a planned baseline. In addition, such a tool provides insight that helps to identify areas with potential for improvements, and to support the right conversations offshore, based on drilling rig-specific data. This highlights where offshore rig crew, individually, can contribute to improving energy efficiency and take the first step towards implementing an increased awareness and thus reducing the overall environmental footprint related to drilling operations.

This paper also provides technical details on how sensor data is being processed in the cloud, where it is managed, quality checked and visualized to guide on- and offshore decision-makers.

It further discusses, through real examples, how important knowledge can be derived through insight and transparency to optimize the operation and behavioral performance, achieving significant decarbonization of the offshore drilling operation, including optimized operation of the rig power plant. Finally, the solution unlocks possibilities for qualified conversations on best practices while benchmarking across a fleet of drilling rigs.
Design and Field Deployment of a Torsional Vibration Damper
Authors: Hohl Andreas , Kulke Vincent , Ostermeyer Georg-Peter , Kueck Armin , Peters Volker , Reckmann Hanno
Published: March 2022

Different vibration phenomena and vibration dysfunctions are excited by the drilling process. The associated dynamic loads result in downhole tool failures and inefficient drilling if not properly managed. Vibration mitigation strategies based on adjustment of operational parameters often compromise the rate of penetration (ROP). The purpose of downhole tools for vibration mitigation is to enlarge the envelope of drilling parameters with low levels of vibrations. The associated more aggressive drilling parameters enable a higher ROP. A torsional vibration damper that is designed to mitigate high-frequency torsional oscillations (HFTO) is introduced in this work along with the results of first field deployments.

A damping-threshold needs to be exceeded by a damper to mitigate self-excited HFTO. The damping threshold is defined through the energy input resulting from the bit-rock interaction and depends on the instantaneous operational parameters. The design space to provide damping, however, is limited. Thus design and dimensioning of the torsional vibration damper is optimized based on theoretical insights, downhole vibration data analysis, modeling and simulations, and laboratory testing at different scale. This process is presented in the paper.

The placement of the damper elements within the drilling system has been identified as a critical task to effectively dampen the critical modes related to HFTO. The simulated results for the BHA that is deployed in the field are presented. In a case study the first field deployments of the torsional vibration damper are discussed. The results of the damper deployments and a comparison to offset well data prove that the damper effectively mitigates HFTO. Snapshots of high-speed vibration data sampled with 1000 Hz are analyzed and related to the modeling results. The suppression of HFTO enabled the application of more aggressive operational parameters and led to an increase in the ROP compared to benchmark runs. First trends prove a high reliability of the BHA with torsional vibration damper tool.

The torsional vibration damper has been successfully introduced in the field and has proven to effectively suppress HFTO. A holistic methodology has been developed that allows for an application specific optimization of the damper deployment. The torsional vibration damper enables a higher rate of penetration at low levels of vibrations and an increased reliability of the tools deployed and, ultimately, decreases the well delivery cost significantly.
Automated Merging of Time Series and Textual Operations Data to Extract Technical Limiter Re-Design Recommendations
Authors: Yi Michael , Ashok Pradeepkumar , Ramos Dawson , Bohlander Spencer , Thetford Taylor , Shahri Mojtaba , Noworyta Mickey , Peroyea Trey , Behounek Michael
Published: March 2022

During the construction planning phase of any new well, drilling engineers often look at offset well data to identify information that could be used to drill the new well more efficiently. This is generally a time-consuming process. The objective was to develop a recommender system that would automate the process of identifying potential hazards and current technical limiters.

The developed methodology consisted of three parts. First, a system is developed that can parse textual information found in daily reports to identify key events that occurred in offset wells. Second, time series data from these same offset wells is processed to identify events directly from the patterns in the data, and a reconciliation is done between the time-series data and the contextual data wherever there is a conflict between the two datasets. Finally, KPIs are computed that enable the comparison of various drilling choices and their consequences across the set of offset wells and recommendation are automatically generated for improvements in the construction of a new well.

The system was developed on a set of 7 recently drilled wells chosen from a specific North American land operation. The recommendations were compared to recommendation made through manual processing of the data for validation of the approach. The recommender identified invisible lost time (ILT) and potential non-productive time (NPT) scenarios, optimal depth-based drilling parameter for the new well, and recommendations on BHA and flat time improvement areas. Open-source natural language processing libraries were used in this project and were very effective in extracting events from textual data.

An automated system was built to guide the drilling engineers in the planning phase of a well construction activity. Given a set of offset wells, the system combined both the time series data and textual data to arrive at these recommendations. The approach upon further refinement is expected to save 30 to 40 hours of the engineer's time per well and shorten the learning curve.
New-Generation Geothermal Wells – How the Upstream Oil and Gas Industry Can Bring Its Experience to Bear
Authors: Clegg John , Krase Steve
Published: March 2022

As renewables are forecast to take a larger and larger slice of the energy mix going forward, the upstream oil and gas industry needs to look at whether and how it can be involved with these new sources of energy in order to maintain its share of the energy mix. Providers of services and technology to the industry should be thinking about how they might be able to apply their skills and capabilities in other, adjacent industries and should begin to think of themselves as energy service companies and not oilfield service and oilfield equipment supply companies.

As the world searches for and attempts to bring on alternative sources of energy, the "holy grail" is a renewable energy source that can provide 24/7 baseload power without releasing greenhouse gases. Wind and solar both have issues with intermittency and therefore with capacity, and will require additional storage capacity – for example, batteries – in order to be able to deliver baseload. More traditional energy sources suffer from significant greenhouse gas emissions. Geothermal is currently the only source of energy which has the potential to provide clean power at scale and in a way that can provide uninterrupted baseload for an electrical grid – without the requirement for storage and the unnecessary consumption of resources this would entail. Serendipitously, geothermal drilling also has many similarities with drilling for oil and gas. The paper will review how geothermal installations are evolving beyond traditional hydrothermal wells and how they will include closed loop systems which seek to extract heat, and not hot water or steam, from the Earth.

This paper describes the various types of new geothermal systems that have been proposed with some commentary on what has been achieved to date. It identifies both similarities and differences between the various well types required for these "unconventional" geothermal systems and the many different challenges in terms of well design and construction that our industry has developed, and perfected over more than 100 years. The similarities that are identified can be thought of as near-term opportunities for the oil and gas drilling industry to apply its skills, technologies and people to this new and growing sector.

The differences can be thought of as challenges that our industry will have to overcome in order to be a valuable part of the inevitable transition that will take place in the near future.
Advancing Influx Detection Toward Automated Well Control
Authors: Dow Blaine , Ferrando Pierrick , Abolins N.I. , Leonard Tom , Abuelaish Ahmed , Gallinal Cuenca Nicolas , Hansen Jerry , Rojas Rodriguez Freddy
Published: March 2022

Beginning in the early 2000s, the industry has applied a lot of attention, effort and protocol toward drilling automation routines in the interest of advancing efficiency and consistency, and most of all, safety. The routines that have grown in maturity and gone mainstream blend data interpretation from advanced algorithms and apply actions to downhole and/or surface machines to achieve the desired outcome. Directional drilling stands our as one field that has proven successful. Well control has been pursued with less enthusiasm in the automation space. Some effort has gone into automating a segmented well control workflow. A fully closed loop automated workflow that detects and controls has not reached commercial maturity yet.

A key challenge for the pursuit of a fully closed loop influx management routine is detection. The data signatures that present themselves remain difficult to interpret consistently. This may be due to the wide range of variables that influence the interpretation. The drilling fluid, reservoir fluid and pressure, and the drilling state when the influx initiates are only a few.

This paper will describe and demonstrate new technology that improves upon a process used since 2014, targeting the most important step of advancing early kick detection. This new generation of algorithms and workflows reduce gain and loss detection thresholds, can enable kick tolerance reduction, and will also minimizes false alarms. As dynamic pressure management and primary well control techniques become more complex, so to, do the challenges associated with the prompt and accurate detection of gains and losses. The new algorithms and workflows have been developed to ensure compatibility with surface backpressure Managed Pressure Drilling (MPD) systems, as well other techniques such as riser annulus height control.

With increasingly stringent environment regulations being implemented worldwide, it is becoming essential for drilling operations to not only detect gains and losses, but to also monitor subsea equipment to avoid unplanned releases of drilling fluid. A side benefit of accurate gain and loss detection also enables detection of such leaks from subsea equipment. The case studies presented here will focus on the results obtained while running this technology in both conventional mode, and MPD mode. Additionally, a case study will describe how the detection application is then coupled with applied backpressure MPD and previously developed work automating circulation of the influx in SPE-194089-MS, attempting to fully close the automated influx management loop.

Beyond the technology, human factors remain a barrier. To break these barriers, validation under robust conditions is essential.
ROP Optimization using a Hybrid Machine Learning and Physics-Based Multivariate Objective Function with Real-Time Vibration and Stick-Slip Filters
Authors: Singh Kriti , Siddiqui Fahd , Braga Daniel , Kamyab Mohammadreza , Cheatham Curtis , Harclerode Brian
Published: March 2022

This paper presents a multi-dimensional optimization engine for optimizing real-time drilling operations by increasing Rate of Penetration (ROP) while reducing Non-Productive Time (NPT) events such as vibration, stick slip, and directional divergence.

A key breakthrough here is the development of the vibration health monitoring tool that tracks and filters out recent drilling parameters responsible for high vibration and monitors the overall BHA health. Measurement While Drilling (MWD) or Rotary Steerable (RSS) providers often provide vibration data but are rarely used in real-time decision making by operators due to the lack of a standardized workflow and technology. A vibration monitoring tool is developed that consumes real-time data from downhole MWD/RSS providers for each axis - axial, lateral, and torsional. A database is created for common MWD/RSS tools containing information about moderate and severe thresholds for shock (G) and average (GRMS) values. The algorithm categorizes vibration data into "low", "medium" or "high". The overall tool health is computed by tracking the cumulative count of the shock values and time corresponding to the moderate and severe categories and comparing against the downhole provider’s specifications.

A multivariate objective function is used to find the optimal Differential Pressure (DPRES) and Top Drive RPM (TDRPM) values from a parameter sweep within user-specified limits or default tool limits. The objective function consists of three components - ROP, downhole MSE, and rotational tendency. A machine-learning model is used to predict ROP as a function of DPRES and TDRPM values, whereas standard drilling equations are used for calculating MSE and rotational tendency. After eliminating the parameters correlated with high vibration or stick-slip instances in the previous 1,000 ft, the optimization engine recommends DPRES and TDRPM values that correspond to the minimum value of the objective function.

The recommendations from the multivariate objective function are presented in the form of a drilling advisory system. The advisory system was tested live on a drilling rig in collaboration with an operator. The results from the field test are presented in the paper.
Designing Drilling Fluids Rheological Properties with a Numerical Geomechanics Model for the Purpose of Improving Wellbore Stability
Authors: AlBahrani Hussain , Alsheikh Mohammed , Wagle Vikrant , Alshakhouri Aqeel
Published: March 2022

Wellbore instability remains one of the major causes of non-productive drilling time and a source of risk that can jeopardize the well objectives. Traditionally, the mud weight has been used as the main parameter through which instability is constrained. This approach fails to consider the dynamic nature of operations. While the mud weight is used to estimate the necessary downhole hydrostatic pressure for preventing breakouts, there are several events and considerations related to dynamic wellbore hydraulics and rig equipment operation than can substantially negate the influence of mud weight. This deficiency can be overcome by integrating the design of the drilling fluid rheological properties with a suitable geomechanics model. The integrated approach relies on estimating the downhole pressure fluctuations in dynamic settings and assessing their influence on wellbore stability.

The integration process is achieved through the use of a finite element geomechanics model with different wellbore hydraulics models that are applicable to a variety of operational scenarios. The first step in the analysis is defining the operational scenarios that can lead to downhole pressure fluctuations. These include well control incidents, circulating versus static conditions, and surge and swab effects while running in and out of hole, respectively. Once the scenario and the corresponding pressure fluctuations are defined and determined, the finite element geomechanics model is used to assess the influence of the pressure fluctuations on the wellbore stability. The final step in this analysis is proposing adjustments to the drilling fluid rheological properties. This will constrain downhole pressure changes to a range that can minimize instabilities. This step is supported with lab experiments to ensure that the proposed drilling fluid formulation can fit the design criterion.

The analysis shows that for each operational scenario, apart from the mud weight, the drilling fluid rheological properties have a tangible effect on wellbore breakouts. It also shows that different operational scenarios can dictate completely different adjustments to the drilling fluid formulation. For example, the addition of a viscosifier to the fluid formulation can be beneficial in a scenario involving a well that is experiencing a gas kick. This aids in maintaining a high equivalent circulating density that counters the downhole pressure reduction caused by the gas intrusion. In another scenario with a well exhibiting surge and swab effects, the reduction of a viscosifier or the addition of a thinner can also be beneficial for constraining the downhole pressure fluctuations, which causes wellbore instabilities and other failures.

The design approach proposed in this work provides a unique perspective that joins geomechanics modeling with drilling fluids formulation and operational considerations.
Rules Engine Exchange: Driving Operational Excellence Through an Advanced Real-Time Alerting System
Authors: Groh Alex , Olson Trevor , Nenninger Carter , Godumagadda Anil , Corne Evan
Published: March 2022

The purpose of this paper is to discuss the development and application of the Rules Engine Exchange (REX®), an ongoing implementation of a real-time alerting system for onshore drilling operations. REX® is an interactive feature integrated into a company-wide analytics platform where users can create and subscribe to alerts monitoring several data sets. Notifications are delivered via SMS/text, email, and web portal.

The system is unique in that it simultaneously utilizes data from electronic drilling recorders (EDR), drilling controls systems, morning reports, and results from real-time models calculated on the rig site. All users can activate pre-written alerts that are quality-controlled by an in-house team of analysts to greater than 95% accuracy. Additionally, any user can write custom, complex alerts written in common programming languages, with minimal training or the need to work with subject matter experts. This platform offers flexibility and speed to users, of varying technical background needing access to high-quality information regarding operational events.

Initial work consisted of interviewing key stakeholders and gathering requirements for a real-time alerting system, with end users in the field and supporting office personnel being a primary focus. The system was closely field followed in the beta test phase, with multiple iterations being completed to prepare for production release. The system was deployed to all company departments with one-on-one training of key users and ongoing support as needed.

For this paper, the authors have chosen two areas of focus to discuss how REX® impacted operations at the field level: 1) optimal generator usage, to allow operations management to be notified of suboptimal generator management, enabling more fuel-efficient operations and lower greenhouse gas emissions and 2) procedural compliance, to allow company personnel to standardize connection practices and prevent BHA damages while coming on and off bottom. The overall usage and adoption of REX®, impact on the above operations, and lessons learned from the perspective of an onshore drilling contractor are discussed below.
Fifty Ways to Leave Your Wellbore: An Honest Look at the Causes and Costs of Unplanned Sidetracks
Authors: Willerth Marc , Dodson Briana , McCue Kelton
Published: March 2022

Unplanned sidetracks are low-frequency high-cost events that have meaningful negative impact on the economics of oil field development. While it is clearly desirable to reduce the frequency and severity of unplanned sidetracks, without a robust baseline for event frequency it can be difficult to estimate the value and efficacy of actions taken to mitigate sidetrack risk. For high volume drilling operations, there exists enough data to establish a meaningful baseline. This study aims to quantify the costs of unplanned sidetrack operations to drilling in North America by estimating the frequency of sidetracks, the reason the sidetrack was needed, typical amount of lost footage and time due to the sidetrack being required. With estimates of these values available a better cost-model for sidetracks maybe developed with which sidetrack mitigating technologies and techniques may be better evaluated for return on investment.

A comprehensive set of approximately 6,500 North American wells drilled in a two-year timespan (2019-2020) by a variety of operators, drilling contractors, and directional service providers was analyzed for frequency of sidetrack operations. In each case where a sidetrack was performed, a review was conducted to determine whether the sidetrack was planned, and whether a reason for sidetrack was recorded. Lost footage and time were estimated from survey records the original holes and the sidetrack wellbores. Cases where there was an intervening well drilled before attempting a sidetrack were excluded from lost time analysis. Also reviewed were case where multiple sidetracks were ultimately required for successful drilling of each wellbore, and whether an initial sidetrack increases or decreases the risk additional sidetracks being required.

There were over 450 wells that required at least one sidetrack. Most of these sidetracks were unplanned and fell into one of four major categories: Equipment lost in hole, directional drilling error, unplanned geology, and hole quality problems. These four categories accounted for nearly 95% of all unplanned sidetracks. The average footage lost due when sidetracking was 2750ft. The average lost time was greater than two days. For wells that have already performed an unplanned sidetrack, it was found that with each additional sidetrack in a well the risk of requiring an additional sidetrack increases further. This suggests that there is even more value in preventing the first sidetrack than there may first appear.

By establishing baseline rates of unplanned sidetracks for several common causes an expected cost to operations can be estimated prior to embarking on a development campaign. In the future, by demonstrating improved results over these baseline values, new technologies and drilling practices can better estimate the value provided to a drilling operation by mitigate rare adverse events.
A Hybrid Physics-Based and Machine-Learning Approach for Stick/Slip Prediction
Authors: Sheth Prasham , Roychoudhury Indranil , Chatar Crispin , Celaya José
Published: March 2022

Stick/slip causes the slowing down or speeding up of the Bottom Hole Assembly (BHA) that occurs when the energy generated by the rotary system on a drilling rig (in the form of surface rotation) fails to reach the drill bit. This condition results in a buildup of energy in the drillstring, which causes the bit rotation to speed up and slow down. In extreme cases, this release of energy can cause the BHA to stop or even reverse the BHA rotation. This rotation variation can also damage downhole tools, stabilizers, and produce belled connections. Currently, one option to alleviate this problem is for wellsite personnel to manually adjust the weight on bit (WOB) and rotations per minute (RPM) to reduce stick/slip. This option is based on the experience of the personnel. There is also an array of tools and techniques to reduce stick/slip. The aim of the work presented in this paper is to predict stick/slip using surface and downhole sensors for the next stand of drilling, which includes predicting WOB and rotations per minute (RPM) ranges associated with stick/slip classes and their probabilities. This paper presents a method that uses a physics-guided neural network (PGNN). The network leverages the physics models of drillstring systems and reinforces it with machine-learning models, such as fully connected neural networks, recurrent neural networks (RNN) (e.g. long short-term memory (LSTM), and Markov Recurrent Neural Network (MarkovRNN)), and different ensembles of these approaches. Hence the method used here is a hybrid of a physics based and a data-driven solution. The advantage of the hybrid method allows for an estimation of system response beyond the historical parameters, permitting a much better estimation of parameters. This results in a more robust solution for the prediction. These predictions will provide the drilling operator with an understanding of the different WOB and RPM ranges allowing them to transfer the maximum energy to the bit for rock destruction, without exciting the system into stick/slip. Results presented are developed for these approaches that have been applied to data collected over the last decade from different wellsites.
Offshore Complex Decommissioning Utilizing Non-Access Magnetic Ranging Methods for Subsurface Intervention
Authors: Dorey Jamie , Rassadkin Georgy , Sikal Anas , Momot Fabien
Published: March 2022

Globally, there are numerous offshore legacy assets, including offshore platforms, subsea infrastructures, and wells that exist, however, are at or approaching their end of life and require decommissioning. Within the range of infrastructure, there is a subset of assets that are categorized as complex to decommission due to being unable to either gain access to the wellbores from the surface with offshore drilling units or there exist casing integrity issues which restrict the ability to access the wellbore. This paper will outline methods that can be applied in the offshore environment to successfully and economically decommission these assets using sub-surface intervention technology. The long-term environmental impacts of not taking action on these assets can be significant, and up until now, the problem has faced economic challenges and high technical risks to remedy.

The methods for complex decommissioning are drawn from a history of relief well intervention and onshore complex plug and abandonment. This paper will outline the methodology required to lower the risk of offshore complex decommissioning. The methods presented utilize active and passive magnetic ranging technology with no access to the target wellbore.

Experience on land-based operations has proven the methodology for complex decommissioning challenges, which enables wells to be abandoned economically with highly successful outcomes. The process is a permanent remedy to intervene and abandon wellbores mitigating environmental impacts and enabling operators to satisfy the growing change in perception with regards to the environmental obligations of the oil and gas industry.

The methods and technology applied for permanent decommissioning of subsurface assets have been optimized for offshore operations. These processes ensure that the economic cost is controlled through the application of risk-based methodologies and a proven, consistent approach to the execution of the operations. The active and passive magnetic ranging systems are undergoing a constant research and development process to further optimize the operations with the novel methods being shown in this paper.
Annular Creep Barrier Evaluation and Qualification Using Ultrasonic Measurements
Authors: van Oort Eric , Thombare Akshay , Aldin Munir , Lucas Alex
Published: March 2022

It is well-known that formations that exhibit active creep behavior under downhole conditions, such as reactive shales and mobile salts, can form annular barriers across uncemented or poorly cemented annular sections behind casing strings. Such creep barriers can simplify well abandonments, particularly in high-cost offshore environments. Evaluation and qualification of creep barriers in the field, however, have proven challenging and labor-intensive when casing is perforated and annular rock material is pressure-tested to verify its sealing ability. This work seeks to eliminate the need for pressure testing by allowing the barrier to be qualified using only cased-hole log measurements.

Sophisticated rock mechanical lab experiments under realistic downhole conditions were conducted to investigate the formation of creep barriers by North Sea Lark shale. The experiments evaluated barrier formation while varying annular fluid chemistry and temperature. Measurement parameters included creep rate, pressure transmission across newly formed barriers, pressure breakthrough through the newly formed barriers, as well as ultrasonic responses by the shale.

It was found that the Lark/Horda shale has a distinct anisotropic ultrasonic wave velocity profile that uniquely characterizes it. This can be used to identify its presence in an annular space when contacting the casing. A main conclusion is that a Lark shale barrier can be qualified through cased-hole sonic and ultrasonic logging alone without the need for pressure testing if: (1) the magnitude of the wave propagation velocity of the shale behind casing can be confirmed (2077 m/sec for Lark shale); (2) the characteristic velocity anisotropy profile, unique to the shale (~10.1% for Lark shale), can be verified; (3) good contact with / bonding to the casing is observed; and optionally (4) anisotropy in the time behavior of the shale contacting the pipe is observed when the barrier is formed / stimulated artificially. If these conditions are met, then our experiments show that the barrier will have excellent hydraulic sealing ability, with a permeability of a few micro-Darcy at most and a breakthrough pressure that approaches the minimum horizontal effective stress value.

Additional findings are that shale heating will accelerate barrier formation but may damage the shale formation in the process. Extra-ordinary fast annular closure and barrier formation with evident shale re-healing was observed by using a concentrated KCl solution as pore fluid, showing the merits of barrier stimulation by chemical means. This result can be explained by considering the effect of solutes on shale hydration forces.
Enhancing Drill Bit Connections for Reliability and Longevity
Authors: Allison Cliff , Borders Zachary , Donaldson Justin , Grimes Robert E. , Lee Roger K. , Slavens Stephen , Daechsel Dustin
Published: March 2022

Pursuit of drilling the technical limit has been a primary driver of cost and cycle time reduction from the onset in North America shale. This is increasingly evident in today's downhole mud motors, where motors designed to drill in 6.75 in. hole are now rated for 500+hp and over 10,000 ft-lbs of torque. Every unit of power added stresses current materials to the limit and increases the risk of mechanical failure. As will be demonstrated in the following sections, the increased power delivered to the bit now exceeds the strength and reliability of the standard 3 ½ REG connection for drill bits. The integrity and longevity of the drill bit pin connections is the primary focus of this paper.

Details are provided of the technical aspects of drill bit solutions that meet current drilling requirements and recognizes industry trends that will continue to present future challenges for bit connections. This paper also describes the collaborative partnership between an operator and bit service provider that led to success and the development of a long term plan for continuing success.
An Assessment of the Kick Tolerance Calculation, its Uncertainty and Sensitivity
Authors: Thorogood John , Robertson Ewen , Castillo David , Sawaryn Steve
Published: March 2022

Much of the contemporary literature on kick tolerance relates to the practical aspects of the calculation and the effects of the underlying assumptions and necessary simplifications. It tends to a formulaic approach involving unconstrained uncertainties about pore pressure, kick intensity, drilling fluid density safety factors which tend to overlook the inherent complexities of the subsurface environment and the reality of model limitations.

The literature on kick tolerance highlighting the strengths, weaknesses and limitations of the classic calculation is reviewed before describing a first-principles approach to determining the consequences which casing seat strength limitations and strength variations in the overall open-hole section imposes on safe well designs as a result of uncertainties in the input variables and basic model assumptions.

The classic kick tolerance calculation, together with its associated assumptions, yields only a single value for a given set of inputs. The uncertainties and sensitivities are those introduced by the variables and the choice of operational procedures. The Monte Carlo method is employed to explore the effect of uncertainties in the input parameters and associated assumptions.

The analysis is based on the Driller’s Method for kick circulation, with a single bubble insoluble gas with optional allowances for gas gravity and thermal regimes. To examine the various factors influencing kick tolerance, the problem is framed graphically in terms of an allowable influx volume, the dependent variable, against bottom hole pressure, the independent variable, on which pore pressure, its uncertainty, possible variations in shoe strength, strength in the open-hole section, drilling fluid density with associated equivalent circulating density and swab effects can be examined.

Application of the new approach demands significant prior work to determine the uncertainties inherent in the problem. Some of these uncertainties, such as drilling fluid density variations, swabbing and equivalent circulating density must be evaluated by the engineer as part of the normal well design. Other factors, such as shoe strength, pore pressure variability and formation depth error bars must be developed as part of a multi-disciplinary effort within the planning team. Often ignored due to the spatial uncertainties, natural fractures intersecting the borehole could be inherently unstable and prone to hydraulic communication between borehole and formation.

Synthesising some of these considerations into a simple calculation framework allows the effect of these parameters either individually or collectively to be quantified and provides a view of the potential geological uncertainties inherent in a well design. The approach offers a starting point for thinking about the nature of geological uncertainties and carrying them into drilling programmes
Mud Motor PDM Dynamics: A Control Model for Automation
Authors: Samuel Robello , Baldenko Fedor , Baldenko Dmitry
Published: March 2022

Automating drilling operations using modern technology with intelligent control systems is prioritized with respect to drilling process development. The process becomes more complex when a mud motor is used because of the dynamic properties of the control objects, which are interconnected from the surface feed mechanism to the bit. Development of a model that better predicts the dynamic condition when a mud motor is used is discussed. The dynamic characteristics of a positive displacement motor (PDM) are considered as a single system by coupling the hydromechanical processes. This includes, transient pressure, drillstring dynamics, kinematics of the PDM rotor, the mud pump and dampener, dynamic characteristics of the bit, and internal and external system disturbances. The mathematical model includes the hydraulic and mechanical subsystems as well as the relationships of these subsystems. The subsystems include the equations of the processes in their constituent links (i.e., drillstring, hydraulic line, mud pump, downhole motor, bit, and bit feed mechanism). The nonlinear system of differential equations are solved using numerical methods with appropriate boundary conditions in a two-way loop for regulating the load on the bit and flowrate.

The study shows that the transient behavior of the mud motor must be accounted for when automating the drilling process. It has been observed that an instantaneous change in the load results in the transition of the hydraulic motor to a new steady-state mode gradually (for tens of seconds) and is influenced by the transient pressures in the string. The transient process (torsional vibrations) in the PDM occurs until the flow rate stabilizes at the top of motor. A similar hydromechanical effect, if the PDM does not have a sufficient torque reserve, can lead to deceleration of the PDM and might require correction of the weight on bit (WOB) and flow rate. The study also showed that the effect of pulsation dampener resulting in an uneven flow leads to uneven rotation of the mud motor shaft, even if a constant load on the bit is maintained. This study revealed that evaluation of the influence of the deviation of one of the operating parameters on the behavior of the dynamic system is important (Tokhonov, 2019). The choice of optimal control algorithms depends on the accuracy of determining the transfer functions, in particular, with respect to the change in the WOB. Further transfer functions derived can be used to control the surface parameters for drilling.