bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Deployment of a LSTM Neural Network Tool for the Rock Formation Consolidation Inference of Brazilian Sandstone Reservoirs
Authors: Rodrigues Gonçalves da Silva Fabio , Ribeiro Carriço Victor Hugo , Zacarias Ignácio Pereira Alexandre , Leibsohn Martins André
Published: March 2023

The objective of this work is to present a methodology based on the analysis of drilling parameters to infer if a reservoir formation is well consolidated or not, as a support to the selection of sand control strategies.

This work proposes a statistical classification model and the usage of a memory based neural network, known as LSTM (long short-term memory) network. This model explores time series characteristics of the problem and it is validated using a cross strategy. Training performance is evaluated using F1-score, which is a metric that balances precision (percentage of true positives compared to false positives) and recall (percentage of true positives compared to false negatives), chosen because the dataset is unbalanced, there are more samples of one class than the other. The dataset consists of pre-tagged wells, each of them with at least nine hours of drilling data.

Considering 48 cases from different drilled wells, the model was trained to learn how to tag between both patterns. The model analyzes 23 different drilling variables to reach a conclusion.

After training the model, tests were performed and the results showed a high identification efficiency: around 90% of accuracy. That way, mechanical data analysis from the drilling process plays a very important role, supplementing that information and allowing a better understanding of formation behavior by employing what can be considered full-size and a real-time scratch test. Match the collected data with those from wells in which there is logging information, provides geomechanics calibration, and allows consistent rock profiling. It helps to define not only if there is a need for sand control but also the kind of technique to be applied to the analyzed formation accordingly to its consolidation state. The impact of that information is expressive to the completion process.

This feature will be very useful in Brazilian post-salt wells that present sandstone as its reservoir rock formation. Also, as this tool was designed to run in a drilling digital twin, it can be automatically run as soon as the total depth is reached in the drilling phase, providing a fast insight to anticipate completion design.

It is the first time in literature that this approach is used for this specific objective: define if a gravel pack or even any kind of sand control is indeed necessary to be installed based on information gathered while drilling the well. Its great results led this tool to the deployment phase. This work also aims to illustrate the first outcomes of that application in real-time decision-making.
Real-Time Prediction and Detection of Drilling Bit Issues Based on Along-String Measurements (ASM) Along Wired Pipes - A Case Study
Authors: Gomar Mostafa , Elahifar Behzad
Published: March 2023

When it comes to optimizing drilling, the focus is on running the bit into the well and performing the drilling efficiently. Included in this are methods for optimizing rate of penetration (ROP), determining the right time to change drilling bits, and managing bit run to reduce other drilling costs, such as tripping, hole conditioning, material consumption, and detecting drilling problems at the right time. The present study employs a new approach to drilling bit modeling that utilizes along-string measurement (ASM) data to continuously monitor the status of the drilling bit.

A two-pronged approach is employed in the monitoring of drilling bit condition in addition to estimating rock drillability to keep track of change in lithology. First step involves developing a model for polycrystalline compact drilling (PDC) bits. It examines micro forces at the bit cutters and then upscales these forces to parameters applied to the drilling bits, such as weight and torque. Upscaling involves geometric remodeling of bits as equivalent cutters and equivalent blades. In the second part, a data-analytic approach is used to combine continuous measurement of downhole data with the developed experimental-based model. The real-time data is measured by using an along-string measurement system on the wired pipe.

The results of this approach can be grouped into three categories. First, the drilling bit condition is estimated in real time in each equivalent cutter. A quantitative assessment could be undertaken based on model output, or a qualitative assessment could be carried out by analyzing specific energy. Having knowledge of the status of bit, the second conclusion is to monitor rock drillability according to variations in specific energy at the bit and publishing numerical value of rock drillability. In addition, the last corollary is to generate knowledge regarding drill string dynamics and the way to differentiate between vibration at the bit and at the drill string. In this paper, however, the first two outcomes are addressed. This approach is tested on a set of ASM data captured during drilling operations on the Norwegian continental shelf. The results are consistent with those reported from the field.

Currently, the selection and evaluation of drilling bits requires knowledge of nearby well records. A drilling penetration rate model that requires calibration for a specific field may also be used to estimate bit condition in some cases. This research presents a new bit status simulator that overcomes the limitations of existing techniques by applying a delicate and intelligent application of ASM data to predict drilling events and mitigate them in real-time.
Experimental Investigation of Geopolymers for Application in High-Temperature and Geothermal Well Cementing
Authors: Denduluri Veerabhadra S , Ulerio II George , Genedy Moneeb , Juenger Maria , van Oort Eric
Published: March 2023

With recurrent calls for a reduction in carbon emissions, geothermal energy has received increasing attention in recent years as a prominent source of clean energy. With current drilling technology, geothermal wells are being constructed in extremely challenging temperature environments, which could reach up to 600°F/315°C in-situ temperature and beyond. However, geothermal well-cementing technology has not changed much over the past few decades, with Ordinary Portland Cement (OPC) still being the primary choice of cementing material. OPC has several drawbacks such as brittle behavior, shrinkage upon setting, poor bond strength to formation and casing, susceptibility to acid gas attack, temperature-induced strength retrogression, low tolerance towards drilling fluid contamination, etc. These factors could lead to a poor cementing job, thus compromising well integrity and not ensuring proper zonal isolation for the life of the geothermal well. Thus, there is a need to develop an alternative material that is compatible with the geothermal environment and able to provide long-term zonal isolation. With a low carbon footprint, self-healing ability, and low shrinkage sensitivity, geopolymers or alkali-activated materials could be a suitable option to augment or even replace OPC. Some of the previous studies on geopolymers have shown that they could be a potential candidate for oil and gas well cementing and civil engineering applications, with some being stable at very high temperatures (up to 1470°F/800°C). Geopolymers are formed by mixing an aluminosilicate source such as fly ash with an alkali-activating solution, such as sodium or potassium hydroxide or silicate.

The aim of the study reported here is to demonstrate the applicability of geopolymers for geothermal well cementing. An experimental investigation was carried out to understand the behavior of geopolymer formulations made from fly ash, metakaolin, and blast furnace slag in a high-temperature environment. The material properties such as porosity, viscosity, thickening/pump time, compressive strength, tensile strength, and bond strength were tested in the laboratory. It was found that geopolymer formulations can be formulated to have the desired rheological properties with adequate pump time and resistance to drilling fluid contamination. In addition, the formulations can exceed the required compressive and tensile strength for geothermal cementing operations, while obtaining excellent bond strength values. These findings indicate that geopolymers are cementing materials that are well-suited to provide long-term zonal isolation in high-temperature geothermal wells.
Definitive Survey Methodology – Update to an Old Concept for Higher Reliability
Authors: Naschenveng André , Isaac Lucas , Laroca Fernando , Franceschi Cláudio , Neves Alex , Canté Fábio , Ledroz Adrián , Carrasquilla Abel
Published: March 2023

Data quality assurance applied to well positioning optimizes contingency plans to reduce the time to drill a relief well and provides greater reliability in autonomous and remote drilling operations. In addition, it provides the highest degree of agreement with the well design, making it possible to reach the best productive zones of the reservoir and avoid geological risks. This data quality assurance procedure supports the construction of high-productivity wells in the offshore pre-salt fields in Brazil. The objective of this work is to present the results of the Definitive Survey Methodology in pre-salt wells, to improve the survey quality assurance and the reduction of uncertainty ellipses - during operation and in real-time - using two survey tools with different physical principles.

The Definitive Survey Methodology promotes the verification of error models of the survey tools and reduces the Ellipses of Uncertainty (EOU), well to well, creating an external directional data quality assurance, which goes beyond specific internal quality controls used by service companies. The methodology consists of the use of three tests that compare independent surveys. The first and second tests are statistical, Relative Instrument Performance (RIP), and Chi-square, in which the reliability of the used error models is verified. The RIP test is a comparison that produces results with quantitative values about the agreement of overlapping surveys. The Chi-square test is a quality fit test that compares two surveys and their compliances with their error models. The third test is a qualitative geometric test that compares the uncertainty ellipses of different survey tools at the same depth, allowing a quick interpretation of graphic representations and can be applied during or after drilling.

The methodology was applied in four pre-salt wells named in this paper as Well_A, Well_B, Well_C, and Well_D. The final measured depths of the wells range from 5078m to 6801m. The tools used were: gyro while drilling (GWD) for all inclinations in real-time (inrun), GWD outrun memory mode (OMM), drop gyros, and measurement while drilling (MWD). The methodology resulted in a reduction of 74.55% (Well_A), 50.93% (Well_B), 33.69% (Well_C), and 60.05% (Well_D) of the ellipse of uncertainty at the top of the reservoir.

The use of the Definitive Survey Methodology enhances the quality of the directional data, verifying the error models used well to well. The reduction of uncertainties provided by the gyroscopic tool ensures the reliability of the contingency plan and the entry into the top of the reservoir. Consequently, by optimizing the positioning of the wells, it is expected to make the most of the natural resources in the long term, while also building safer contingency plans, and making the extraction activity of this natural resource more sustainable.
Expandable Geopolymers for Improved Zonal Isolation and Plugging
Authors: Gomado Foster Dodzi , Khalifeh Mahmoud , Aasen Jan Aage
Published: March 2023

Generally, the expansion of cementitious materials has been regarded as a promising avenue for better sealability. The sealability performance of an expanding geopolymer is compared to an expansive commercial cement in terms of the shear bond strength and the hydraulic bond strength at curing conditions of 25°C and 34.5 bar. A Neat Class G and a neat geopolymer were characterized alongside its corresponding expansive versions. The impact of these expansive agents on cement and geopolymers is evaluated in terms of linear expansion using the annular ring test. In terms of its performance for P & A operation, the push-out test was used to characterize the shear bond strength between the casing-cement interfaces, whereas the hydraulic bond strength is measured with a custom-made setup which eliminates any pressure and thermal shocks. These materials were characterized in terms of its shear bond strength, hydraulic bond strength and linear expansion. The shear bond strength of Neat G and expansive cement were estimated to be 22.37 bar and 22.76 bar respectively. Whereas that of the neat geopolymer and expansive geopolymer were recorded at 7.47 bar and 10.14 bar respectively. On the basis of the hydraulic bond strength, expansive cement had the highest followed by expansive geopolymer. Both the neat recipes were observed to have the same values in terms of the hydraulic bond strength. This study reveals that geopolymers can be deployed as an alternative to Portland cement upon optimization.
While-Drilling Pore Pressure Surveillance Using Machine Learning
Authors: Raman Rahul , Spivey Benjamin , Fink Richard , Karner Stephen
Published: March 2023

While-drilling pore pressure surveillance enables timely responses to unexpected drilling events, e.g., wellbore instability, or to pressure changes that could impact mud weight requirements or casing depths. The real-time pressure surveillance and analytics (RT-PSA) system described herein aids while-drilling pressure surveillance by highlighting possible pressure trends and detecting pumps-off gas automatically. The system further assists pressure surveillance practitioners by automatically filtering for lithology and providing a visualization dashboard to highlight possible pressure trends.

The pressure trending application calculates slopes/trends for LWD and mechanical data and uses these trends to indicate possible pressure trends along the well path using a heat map. A lithology filtering method has been developed using machine learning (ML) clustering algorithms to remove non-shale data, leaving only clay-rich shale lithology for pressure trending.

The gas monitoring application aligns the gas curves back to the time and depth at which gas is liberated from the formation by the drill bit, called herein as at-the-bit curves. The application displays modified total gas, gas exponent, and gas ratio curves as at-the-bit curves. The gamma ray and resistivity LWD logs are also shifted back to the time/depth that the bit drilled the measured formations. Aligning the gas and formation log curves to be at-the-bit provides the pressure surveillance personnel with additional context beyond traditional gas surveillance data to classify gas measured at the surface as pumps-off-gas or formation gas.

Results demonstrate that the lithology filtering method using machine learning is effective to filter out clay-rich shale. The pressure trending results are consistent with post-drill pore pressure evaluations generated by pressure prediction experts. The shifted total gas and pumps-off gas have been validated versus post-drill pressure analysis. The system is being deployed to mitigate well control events by improving and standardizing pressure surveillance best-practices across a global organization.
Drilling Dysfunction Demystified Using In-Bit Strain Sensors
Authors: Witt-Doerring Ysabel , Pastusek Paul , Lacey Aaron , Barajas Pablo , Bergeron Michael , Clayton David , Sowers Steven
Published: March 2023

Drilling dysfunction causes premature failure of bits and motors in hard formations. Dysfunctions may be influenced by; bit design, bottom hole assembly (BHA) design, rig control systems, connection practices, and rotating head use. Sensors that record weight, torque, and vibration in the bit can offer insights that are not detectable further up the BHA. By understanding the root causes before the next bit run, it is possible to rapidly improve performance and prolong bit life.

The formation being drilled in this study is a hard extremely abrasive shale, requiring 35+ runs per lateral section. The primary cause of polycrystalline diamond cutter (PDC) failure was smooth wear and thermal damage. The wear flats are attributed to abrasion and mechanical chipping that rapidly progress to thermal damage. Higher weights were not effective and it was hypothesized that buckling was occurring, causing insufficient weight transfer and increased lateral vibration. In-bit sensors that measure weight, torque, revolutions per minute (RPM), and lateral, axial and torsional vibration were run in hole to evaluate the weight transfer issues and dysfunction.

High frequency downhole and surface data were combined with forensic images of the bit and BHA to confirm the weight transfer issues. In total, three major problems were identified and rectified during this study: drill string buckling, rate of penetration (ROP) loss due to the use of rotating control devices (RCDs) and WOB and differential pressure (DIFP) tare inconsistencies.

Drill string buckling resulted in the downhole WOB being much less than surface WOB (DWOB<<SWOB) in early runs. Heavy weight drill pipe (HWDP) was run across the buckling zone to correct this. Subsequent runs showed a significant improvement in DWOB, reduction in lateral bit vibration, and improved performance and dull condition.

Significant decreases in DWOB, DIFP, and ROP were noted when running tool joints through the RCD. Although observed before, in-bit accelerometers showed an increased lateral vibration that was a result of the loss in ROP and this continued long after the ROP recovered.

DWOB and downhole torque (DTOR) were often much higher than SWOB and DIFP (converted to torque). Plots of hookload and stand pipe pressure tare values were used as indicators of inconsistent tares. Although premature motor failure were not noted in these runs, premature PDC cutter failure were.

High frequency in-bit load sensing was used to identify persistent lateral vibration after a ROP loss event due to tool joints interacting with RCDs. A team based, continuous improvement, process was used to evaluate the root cause of downhole dysfunction and recommend bit/BHA design and operating procedure changes before the next bit was on bottom. This rapid analysis and joint recommendation process significantly prolonged bit life and improved drilling performance.
Facts, Fallacies and Pitfalls of Using Mechanical Specific Energy (MSE) – Part 1
Authors: Samuel Robello , Mensa-Wilmot Graham
Published: March 2023

Over the years, some researchers have used Mechanical Specific Energy (MSE), which is said to represent the amount of energy needed to drill a unit volume of rock, to quantify drilling efficiency. MSE was originally introduced by Teal for the mining industry in 1964. Since then, MSE has taken different forms for other reasons, based on its interpretation, and intended use. This paper provides a comprehensive review of MSE in general, discusses its different forms and narratives, and draws the readers' attention to common (and not so common) facts, pitfalls, and fallacies, of using MSE.

It has been found that these specific energy concepts are held as true for all predictive purposes in drilling, amended and promoted beyond the original framework. The paper analyzes all the equations presented in the past and quantifies each component of the equations. The hydraulic terms used alongside the mechanical terms are also discussed. Extensive simulations have been carried out and will be reviewed in this paper by quantifying the energy under each term based on rate of penetration effects and implications. We aimed to demonstrate in this paper, the theoretical grounds for pitfalls and fallacies in using MSE.

MSE is made up of two components: torsional energy and thrust energy. The results have shown that the thrust term is much smaller than the second torsional energy term and in most of the cases, about 2% or less. Hence, it could be neglected and thereby the equation results in the form of inverse of the rate of penetration (ROP) making the calculated MSE value redundant when the actual ROP is available. The results also have shown that when the hydraulic energy term is subtracted from the MSE equation, it results in negative rate of penetration and thereby shows a fundamental flaw in the system formulation. The purposed and merits of MSE use, by some researchers to identify drilling dysfunctions, will also be highlighted. In this process, it has been shown that nonlinear "torque wedging" causes inaccuracies in dysfunctions identification and discussions. Also, the field data presented in the paper shows that mechanical energy is not a ratio of input energy and rate of penetration. Moreover, none of the studies have accounted accurately for the effects of bit wear and motor wear on MSE. It has been found that overall, the concept relating to dysfunction quantification is a self-destructive process, which has spread from paper to paper without the required checks and verifications for accuracy. The underpinning discussions have been backed and demonstrated with numerical examples.

The paper provides the pitfalls in the omissions of some of the assumptions in various MSE models used by engineers. This helps the users to carefully plan, design, engineer and construct the wells.
Towards the Correct Interpretation of Real-Time Signals on the Well-Site
Authors: Daireaux Benoit , Brackel Hans-Uwe , Ewald Robert , Markussen Petter , Johansen Maria , Parak Mahdi , Yadav Ghanshyam , Ismayilov Anar
Published: March 2023

Objectives/Scope

Drilling operations rely on the collaboration of many participants, and the efficiency of this collaboration depends on timely exchange of information. The complexity and variability of this information make it difficult to achieve interoperability between the involved systems. Recent industry efforts aim at facilitating the many aspects of interoperability. A central element is semantic interoperability: the ability to correctly interpret the real-time signals available on the rig. This contribution presents an implementation of semantic interoperability using OPC UA technology. It translates the principles developed through joint industry efforts into actual drilling operations.

Methods, Procedures, Process

The process used the steps of characterizing the drilling real-time data with semantic graphs, and then developing methods to transfer this characterization to an operational real-time environment.

A semantic interoperability API (application programming interface) uses the semantic modelling capabilities of OPC UA. Its objectives are to facilitate the acquisition and identification of real-time signals (for data consumers) and their precise description (by data providers). The different components of the API reflect the diversity of scenarios one can expect to encounter on a rig: from WITS-like data streams with minimal semantics to fully characterized signals. The high-level interface makes use of semantical techniques, such as reasoning, to enable advanced features like validation or graph queries.

Results, Observations, Conclusions

The implementation phase resulted in a series of open-source solutions that cover all the stages of semantic interoperability. The server part integrates real-time sources and exposes their semantics. Data providers can use dedicated applications to accurately describe their own data, while data consumers have access to both predefined mechanisms and to more advanced programming interfaces to identify and interpret the available signals.

To facilitate the adoption of this technology, test applications are available that allow interested users to experiment and validate their own interfaces against realistic drilling data.

Finally, demonstrations involving several participants took place. The paper discusses both the testing procedures, the results and insights gained.

Novel/Additive Information

The solutions described in this contribution build on newly developed interoperability strategies: they make on-going industry efforts available to the community via modern technologies, such as OPC UA, semantic modelling, or reasoning.

Our hope is that the adoption of the developed technology should greatly facilitate the deployment of next generation drilling automation systems.
Geothermal Drilling – Collaborative and Holistic Applications Specific Solutions Drive Consistent Improvements in Drilling Efficiency and Operational Costs
Authors: Mensa-Wilmot Graham , Cotanda Rufino , Pazziuagan Dexter
Published: March 2023

Geothermal assets continue to be developed aggressively in several regions around the world, fueled by the need to develop clean sources of energy and the recognition that geothermal energy is one such source. As expected, most Geothermal projects are planned and executed using legacy oil/gas drilling systems, tools, and strategies. While effective in some instances, this approach introduces risks, limitations, and inefficiencies into the geothermal drilling process. Consequently, project cycle times and operational costs are usually higher than expected, with additional negative effects on energy production levels and efficiencies.

These challenges need prompt solutions, which must be achieved through development of geothermal specific technologies and strategies. Such considerations are needed to promote drilling efficiency improvements, sustainable project cost reductions, and facilitation of expanded geothermal asset development. In support of required efforts, this paper presents structured processes that guide the interpretation and understanding of geothermal drilling applications and promote holistic development of geothermal specific solutions. The positive effects of a holistic approach and other processes on geothermal drilling, with a focus on improved efficiencies, cycle time and operational costs reductions, will be presented with supporting field data.
Intelligent Tracers for Fluid Invasion Tracking During Coring Operations
Authors: Al-Qasim Abdulaziz , Godbole Atul , Tayyib Deena , Wurtz Marie , Hartvig Sven
Published: March 2023

Core analysis, if conducted successfully, can provide accurate assessment of the original reservoir fluid properties, however, it is challenging to retrieve an uncontaminated core, due to mud components contaminating the fluids originally present in the reservoir. Due to invasion, the liquid extracted from the cores, does not necessarily represent the native liquid, but rather a mixture of drilling and reservoir fluid, thus affecting the results, conclusions and decisions that were based on the analysis. Therefore, deploying advanced water-based mud (WBM) tracers, during coring operations, can mitigate this issue and lead to a significant cost-reduction in field development.

Tracer technology is an efficient monitoring and surveillance tool, that was proven to help in tracking and understanding the injection flow paths, and estimating the remaining oil saturation (Sor) in the reservoir, through inter-well and single-well tracer tests. Utilizing water-based tracers in the drilling mud, during coring operation, can help in quantifying the degree of invasion in the retrieved cores, therefore proper correction and more accurate assessment of the reservoir rock and fluid properties, can be made.

The accuracy of the data plays a pivotal role in guiding the way forward and the future development of oilfield projects. A WBM tracer was utilized in the drilling mud, during the sidetracking of an observation well at the first and largest CO2-Project in the middle east. The objective of sidetracking the well was to obtain sponge core samples to assess the residual oil saturation (ROS) and evaluate the sweep efficiency of the CO2-flood.

This report provides an overview of tracer technologies and the lessons learnt from deploying advanced water-based mud (WBM) tracers during the coring operation of a CO2 observation well, including theoretical and experimental considerations, engineering design and field test issues. The objective of this tracer survey was to estimate the invasion of the drilling mud-filtrate and correct water saturations. It will be useful to use this deployment in some of the relatively mature fields, however, it may have some limitations and challenges that need to be addressed first.
A General Framework to Describe Drilling Process States
Authors: Cayeux Eric , Macpherson John , Pirovolou Dimitrios , Laing Moray , Florence Fred
Published: March 2023

Automation and digitalization of drilling requires shared knowledge about the state of the drilling process: is the bit on-bottom drilling or is the driller making a connection; is the borehole in good condition or is it sloughing? Yet there is no shared, clear and usable definition of what a drilling process state is, nor an agreed method to calculate it. In this paper, we propose a method to clarify the concept of drilling process state. A set of partial differential equations, respecting boundary conditions, can describe drilling operations. The set of all possible discrete changes of boundary conditions, therefore, defines the set of all possible drilling process states. Equality or inequality of logical expressions of at most two boundary values characterizes a discrete change of a boundary condition. For instance, if forces applied to the bit by the formation are zero, this corresponds to an off-bottom condition, while forces greater than zero means that the bit is on-bottom. Such simple logical conditions are microstates, and an orthogonal set of microstates defines a drilling process state. An analysis of the drilling process from the perspective of these microstates defines an orthogonal basis of microstates. It is possible to define uniquely any drilling process state in this orthogonal basis. There are a finite number of possibilities to move from one state to a different state by changing only one single microstate, which leads to the construction of an implicit graph of possible states. In this implicit state graph, the change from one state to another state that corresponds to more than one modification of the microstates corresponds to a path in the graph. However, the microstate basis depends on the type of drilling process. The paper will provide examples of different microstate bases for conventional drilling, backpressure managed pressure drilling, and dual-gradient managed pressure drilling. Microstates also cover abnormal drilling conditions, such as hanging on a ledge, or flow obstruction in the annulus by a pack-off. They are, therefore, more powerful descriptors than "rig activity codes". The required fidelity of the drilling process state depends on its use, for example for controlling drilling equipment (process control), for calculating key performance indicators (process statistics), or for user feedback (human factors engineering). This work is part of the D-WIS initiative (Drilling and Wells Interoperability Standard). D-WIS is a cross-industry workgroup providing the industry with solutions facilitating interoperability of computer systems at the rig site. The definition of a microstate is a simple logical statement, easily implemented in computer software. The paper provides an example of a simple algorithm, which will enable others to leverage the work in the commercial, interoperable, environment.
Continuous Improvement for Offshore Plug and Abandonment, a Case Study from Egypt Offshore
Authors: El Nadoury Mohamed , Balbaa Ola , Vincent James , Eberhardt Todd , Moussa Mohamed , Galal Alaa , ElKholy Sherif , Younan Joseph , Sabra Mohamed , Bogaerts Martijn
Published: March 2023

Setting cement plugs is a critical operation, often not getting the required attention and potentially resulting in lost time. For example, while drilling an exploratory well offshore Egypt in the North Ras el Ash block, special attention was given early in the well's design phase to the wellbore abandonment to be executed after reaching the well target and achieving all well's objectives.

As part of the continuous improvement, a detailed after-action review (AAR) took the place of the abandonment of the previous exploration well in the same field ahead of spud. All applicable lessons learned were identified and worked out in easy-to-implement steps to improve the chances of a successful abandonment meeting all company and regulatory requirements. The AAR addressed all aspects of the abandonment, including cement slurry design and laboratory testing, cement plug placement and operational rig procedures, and post-placement activities that could impact the cement plug and, in the worst case, could lead to not meeting abandonment requirements.

All plugs to be verified by a positive and negative pressure test were simulated using proprietary software. The simulation results would predict the cement plug bonding to the formation or casing during and after the positive and negative tests. To overcome any damage in the sealing capability of the plug, those plugs were designed so that the slurry would expand during the cement setting phase. In addition, detailed laboratory tests were run to optimize the cement slurry design at actual downhole conditions.

Special attention was given to formation pressures and possible losses or influx after cutting and retrieving the intermediate casing. Certain shales are gas-bearing formations but with very low permeability and very low capability to deliver gas to the wellbore. During the drilling phase, this is not considered a high risk and was easily managed with drilling fluids. However, while setting plugs, a small influx of gas can percolate through the cement plug creating a potential leak path.

Correct placement in the field is equally important to a good design. The plug placement was simulated to minimize contamination during placement for plugs. Optimum spacer volume, underdisplacement, and the use of mechanical separators were optimized to achieve the plug and abandonment (P&A) objectives. Pull out of hole (POOH) was designed to minimize disturbance of the cement plug and circulation at top of cement (TOC) was performed without disturbing the cement/spacer interface.

All the effort placed into the well abandonment during the well design phase paid out during the execution. A total of five cement plugs were planned. The plugs were tagged and tested achieving all the abandonment requirements successfully. No repeat plugs were required.
Designing and Qualifying Equipment for a Potential World-Record Deepwater Casing Landing Operation
Authors: Chase Thomas , Garcia Aaron , Marchman Kellon , Mendoza Manuel , von Eberstein Chris , Tritz Jacob , Tritz Noah , Jordan Chris , Smith Logan
Published: March 2023

As the design of deepwater wells continues to evolve for unlocking new reserves from deeper and challenging reservoir conditions, longer and heavier casing strings are required to achieve various well objectives and operational efficiency. The mechanical requirements resulting from the landing and cementing of these heavy casing strings pushes the limits on current equipment. Landing and cementing such heavy casing designs presents numerous challenges to conduct the operation safely and efficiently, requiring the implementation of non-conventional alternatives to manage the loads for enabling the existing rigs to step-out of the normal drilling envelopes.

For drilling the first deepwater 20,000 psi development well in Gulf of Mexico, the Operator required the large diameter nested liner strings to be deployed deeper than any offset well, for ensuring pressure containment while drilling and sufficient diameter for the larger production casing / completion equipment. As a result, the load of landing the 16″ nested liner string was expected to exceed 2.5 million lbf, which was outside of the operational capability of any existing equipment, including drilling rig, landing string and cementing head. The planning team assessed alternatives for running the liner with an existing drillship and the landing equipment available including pipe, cementing head and handling equipment. Rigorous measures had to be put in place in order to determine the technical requirements to qualify the equipment for the operation and better understand and mitigate the risks involved.

These challenges were overcome by considerable planning in landing string design, handling equipment implementation, assessing rig load path and shearing capability for the heavy landing string, equipment design review and testing, and equipment inspections and qualifications. Specific areas of focus included: the use of heavy-duty, high yield, thick wall landing string through the BOP stack, upgrading the shearing and sealing capability of the rig's BOP stack, use of buoyed landing string above the BOP stack and the associated handling equipment, an increased load rating of cementing equipment by re-evaluating design and material, customized inspection criteria for all equipment to be used, and a thorough evaluation of landing string accessories to validate structural integrity. All parties involved provided significant effort to ensure that the equipment used in this string was fit for purpose.

The stringent planning, ratings re-evaluation, and equipment qualifications helped ensure the successful landing of a potential world-record 2.49 million lbf hookload 16 in. liner string under challenging weather conditions. The successful landing of this string paves the way for future wells where similar design challenges will be faced.
Engineers’ Trilemma: Use and Limitation of Torque and Drag Models
Authors: Samuel Robello
Published: March 2023

Different methods to calculate torque and drag have been used by the oil industry for years. Various assumptions are used in formulating these models. Opinions have often varied as to which model is better and whether the assumptions are valid. This paper discusses the trilemma considerations for an engineer 1. Soft string model vs stiff string model 2. Survey calculation method based on minimum curvature 3. Appearing and vanishing tortuosities after the casings have been run.

Because of various underlying assumptions, the friction factor calibration is done often to match the calculated results with the actual results. This results in a wrong conclusion due to the change in the drag forces but on the contrary, it may be due to the exacerbation of the assumptions. The paper presents the pitfalls of the drillstring models, borehole curvature, appearing and vanishing tortuosities and their relationship with related well engineering calculations. Mathematical underpinnings are provided for all the trilemma considerations.

Results demonstrate that a string with a large-size section can be very soft in a straight wellbore, and a string with small-size section can be very stiff in a wellbore with severe tortuosity, which is better fit for a stiff string model. Results also confirm that the soft string model is a better choice when the string is slimmer, the wellbore is in a lower curvature shape, and the clearance is larger. It has been observed that the absence or the discontinuity of bending moment results in the underestimate of forces, torque, and stresses when the minimum curvature method is used. This vanishing tortuosity alters the apparent wellpath and the new tortuosity representative of the cased hole path may present new appearing tortuosity and results in over and under estimation of the torque and drag calculations. To accurately estimate the drag force, the stiffness, as well as the wellbore shape and its clearance, should be considered.
Evaluation of Stress Distribution in Subsea Wellheads Installed in Caisson
Authors: Cantinelli Sevillano Lucas , Sangesland Sigbjørn , Gjersvik Tor Berge , Faanes Audun
Published: March 2023

The wellhead is a pressure containing vessel at the top of well and acts as the mechanical connection between well and blowout preventer (BOP), or Christmas tree. Wellheads in subsea wells are subjected to dynamic loading, and consequently fatigue damage, whenever a riser connects a well to a floating vessel. This paper investigates the load distribution and stresses along the components of subsea wellheads installed in a caisson, as an alternative to mitigate wellhead fatigue.

To prevent fatigue-related incidents, operators, suppliers, and classification societies have collaborated to improve the evaluation of wellhead fatigue. A detailed finite element model (FEM) of the wellhead is used to simulate the mechanical response of the system and calculate stress levels at relevant spots. The simulations presented in this study follow the industry's recommended practices to investigate the potential of reducing the loading on wellhead fatigue hot spots by having a caisson installed around the conductor. Different parameters were established to evaluate the sensitivity of the system's response and determine the optimal mechanical configuration.

Caissons have been used to place the wellhead and the Christmas tree below the mudline level, as a protective measure against icebergs in Arctic regions and trawl nets in fishing areas. The results of the presented study case indicate that this practice may be of benefit to subsea wellheads in general. The interactions with the caisson and the thick cement ring between conductor and caisson near the mudline may alter the response of the wellhead to the environmental loads transferred by the riser. While the magnitude of the loading itself is not reduced, its distribution along the wellhead components is. As a result, stresses on wellhead spots particularly vulnerable to fatigue failure, such as welds, may be reduced, while stresses on other, less vulnerable, locations of the wellhead may increase, which still results in a net gain to the overall service life of the product.

Installation of a subsea wellhead in a caisson is a potential fatigue mitigating measure applicable to new wells, either in satellite or clustered configuration. The industry's established experience with similar equipment may expedite the adoption of this measure.
Pressure On-Demand - Hybrid Electric BOP Control Systems
Authors: Givens Matthew , Olson Matthew , Hope Joseph , Beim Samantha
Published: March 2023

Changing well control requirements have increased accumulator volumes for the operation of Blow Out Preventer (BOP) stacks and diverters, challenging the space available for the BOP control system equipment on today's rigs. Koomy or Land Closing Units (LCUs) use potential energy stored in accumulators to control the hydraulically actuated BOP Stack and diverter systems. Accumulator systems are limited in their operational capacity because of the inefficiencies created by rapid adiabatic gas expansion and the pressure and flow decay over the function stroke. By changing the approach from stored energy in accumulators to energy on-demand, the hybrid electric BOP control system will expand the operational capacity drilling rigs.

The implementation of a hybrid-electric pressure on-demand BOP control system can reliably address this challenge by providing indefinite usable volume and a more reliable platform with a smaller footprint and value-added performance. Feedback loops will provide on demand flow to better match the operation and shear curves of the individual functions, eliminating the BOP closing time and response constraints that challenge traditional accumulator systems. This paradigm shift will remove the usable volume constraint as the pump on-demand system provides an indefinite amount of flow at the maximum rated working pressure of the operating piston.
Stringer Detection and Drilling System Significantly Reduces the Invisible Lost Time (ILT) Caused by Reaming
Authors: Hohl Andreas , Houghton Glen , MacFarlane Danial
Published: March 2023

Drilling hard stringers that are erratically distributed in an underlying rather soft formation is challenging from different perspectives. An unforeseen change of the drilled formation from soft to hard and dense rock can cause impact damage to the bit, deflect the bottom-hole assembly (BHA), result in high bending loads, increase vibration, and cause wear/tear on BHA components. If not properly managed, this leads to non-productive time (NPT) and increased maintenance costs. Further, a deflection caused by a stringer away from the planned well path that is detected late results in high local doglegs (HLD) and requires time-consuming correction through reaming with invisible lost time (ILT).

Recently, a stringer detection method based on vibrations, namely high-frequency torsional oscillations (HFTO), has been presented. A case study with 21 sections in the North Sea based on this solution is shown that demonstrates a reduction in ILT by 80%.

The system is based on a timely and reliable detection of stringers, an optimized mud pulse telemetry scheme, and an automated advisory system. The downhole algorithm embedded in a measurement while drilling tool is consistently interpreting HFTO based on tangential acceleration and dynamic torsional torque measurement. By defining thresholds for the amplitude and the localization with respect to frequency content of HFTO, the algorithm results are translated into a binary value with 1 – stringer currently drilled or 0 - no stringer is drilled. The low bandwidth consuming 1-bit value and downhole measured bending moment are sent in 10 to 15 second intervals to the surface by mud pulse telemetry. Once the stringer is detected, the bending moment data is closely monitored to react correctly and efficiently to a stringer in different scenarios.

This solution is discussed in a case study in Norway covering 21 sections with and without the system deployed. The offshore application is challenged by frequently occurring stringer layers and nodules of different geometry. Based on the stringer content, the reaming time has been typically high in this application. The system, however, enabled a timely detection of the stringers and an optimal stringer drilling enabled by the frequently sent bending moment information. Therefore, stringer drilling was done without having to pull off-bottom frequently and ream the transition area between soft and hard formation thereby saving time and reducing wear on the BHA and drill pipe, ultimately ending up with a smoother/straighter wellbore.

By using the system, a faster reaction to any stringer and the use of appropriate parameters to avoid costly HLDs are achieved. The case study demonstrates a significant and consistent improvement in ILT. The reaming hours per 1000 m as a benchmark have been reduced from 2-5 hours without to 0.3-0.6 hours with the system resulting in an average saving of 12 hours per reservoir section.