bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.