bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsea Driving of Conductors: a Cost Effective and Successful Alternative to Pre-Drilling for Moho Nord TLP Development
Authors: Navez Guillaume , Delabrousse-Mayoux Géraud , Moysan Anne-Gaëlle 
Published: January 2016

Abstract
Reducing deepwater development costs involves thinking about alternatives to the most conventional techniques and increasing synergies among disciplines. For deepwater well conductors, replacing the conventional jetting installation method by subsea driving constitutes, in some applications, one such cost-effective alternative. On the Moho Nord Tension Leg Platform (TLP) development in Congo, all 27 conductors were installed in only a few days with an installation barge and using subsea hydraulic hammers, an operation that would have taken a few weeks and would have cost significantly more if jetting had taken place from a deepwater rig.
This paper presents, from the perspective of an operator's drilling entity, some of the experience gained from this project. First, the reasons and development concept specificities which led to preferring this installation method are introduced. Then, the main engineering steps are addressed in some detail, from the geotechnical studies and the driving predictions to the fatigue engineering of both the conductor pipe and the conductor housing, and then recommendations relative to their specifications are made. The challenges regarding the engineering and procurement planning are highlighted and briefly discussed. The selected driving methodology, from the handling of the conductors to their driving to final penetration, is also addressed. Finally, the operations are debriefed in a post-job review.
Whereas conductor or pile driving has been used extensively in other applications and/or industries (shallow water drilling, offshore construction, etc.), its use in deepwater drilling operations with subsea hydraulic hammers and wellhead systems is recent and the published knowledge is therefore scarce. This paper adds to the body of knowledge by providing offshore development project managers and engineers with first-hand information about this alternative to jetting conductors, its potential benefits, and key engineering and operational challenges to be considered to make it a success.
Next Generation Kick Detection during Connections: Influx Detection at Pumps Stop (IDAPS) Software
Authors: Tarr B. A. , Ladendorf D. W. , Sanchez D. , Milner G. M. 
Published: January 2016

Abstract
At least 25% of all influx events on deepwater wells occur while making connections but few deepwater rig contractors employ kick detection alarms to alert the driller during a connection (Brakel et al. 2015 and Fraser et al. 2014). Due to the transient flow characteristics associated with connections, kick detection during connections is the most challenging to automate effectively. The Influx Detection at Pumps Stop (IDAPS) software was developed to provide early warning of abnormal flow back conditions during connections. Available flow-in, flow-out, pit volume, bit depth and hole depth real-time data is used as input data. Particular attention was paid to achieving high probability of detection (PD) at low false alarm rates (FAR) to minimize nuisance alarms, and fast influx detection times to reduce kick volumes. The use of IDAPS to reliably detect a formation fluid influx has improved safety, operational efficiency, and driller situational awareness. IDAPS has been deployed in an operator's real-time operations center for monitoring critical offshore wells since 2014.
During IDAPS operation, pumps-off occurrences are automatically detected and saved as unique events. Machine learning algorithms are applied to recent pumps-off event flow-out and pit volume data patterns to adaptively calculate limits for "normal" events. The adaptive nature of these limits allows IDAPS processing to adjust to changes such as increasing hole depth. Each new pumps-off event is evaluated in real-time and statistically meaningful deviations from the recent "normal" limits generate corresponding possible influx notifications at one of four confidence levels (low, medium, high, and confirmed). Additionally, based on data pattern recognition algorithms, the software detects and notifies the user of circulation system data validity issues that could otherwise impair influx detection performance, e.g., malfunctioning flow sensor, unusual pit volume gains, etc. Overlay plots of current and historical flow and pit volume data have been shown to be valuable in significantly reducing the time required by the user to validate anomalous pumps-off event data automatically identified by IDAPS.
Based on an extensive validation process, using available historical real-time data, the demonstrated false alarm rate for IDAPS was 1 per 195 connections with a 100% influx detection rate, with an associated confirmed influx detection time as fast as 84 seconds after pumps stopped.
Optimization of Rate of Penetration in a Convoluted Drilling Framework using Ant Colony Optimization
Authors: Jiang Wanyi , Samuel Robello 
Published: January 2016

Abstract
This paper presents a combination of artificial neural networks (ANN) and ant colony optimization (ACO) used to determine optimal rate of penetration (ROP). The Bayesian regularization neural network (BR-NN) was trained and compared to the modified Warren model for ROP. The efficiency and effectiveness of ACO was evaluated for the optimization of ROP. There is no acceptable universal mathematical model that accurately describes ROP because of complex downhole conditions. Analytical models or real-time data analytics are usually used separately to estimate and predict ROP. Combining and using both methods simultaneously enables efficient ROP estimates and predictions. ANN can calculate ROP as output; inputs include depth, weight on bit (WOB or W), rotational speed (N), mud flow rate (Q), and gamma ray. ANN can potentially be used with real-time raw data without an explicit mathematical model for ROP. ACO is an algorithm that mimics ants determining the shortest path between their nest and food source. The ACO algorithm for the travelling salesperson problem (TSP) is modified to optimize ROPs. BR-NN with three hidden layers is selected. The trained BR-NN compares to benchmark data with a correlation coefficient &gt; 0.99. ANN is considered suitable to calculate ROP (or ROP0 without the bit wear term) from drilling parameters, including W, N, Q, depth, and gamma ray.
Similar to a typical ACO algorithm for TSP, the pheromone update includes three terms: decay, recent ant activity, and elite path of shortest distance. In the probability function, the ROP reciprocal (i.e., drilling time) replaces the distance. For the test example, ANN-based ACO reproduces the global optimal ROPs, which are obtained by brute force for the test example. ROPs can be overestimated because bit wear is assumed constant for each depth. By separating the bit wear term from ROP, ACO provides an optimal overall drilling time as compared to actual drilling time. The paper presents field examples to predict and estimate optimal drilling parameters. The ROP estimate using the new model was performed using actual drilling parameters. The calculated ROP profile closely matched the actual data with an error rate of less than 5%. The paper proposes specific procedures to estimate drilling parameters and predict ROP and bit life. ANN was used to calculate ROP from input data with high accuracy. This is the first time an ACO algorithm is examined for ROP optimization, and ACO reproduces the optimal ROPs for the test example. This study combines ACO and ANN and shows their great potentials in optimizing real-time ROP based on real-time measurements.
Mitigating Vibration Induced Drillstring Failures Using Data Analytics: Workflow and Case Study
Authors: Mirani Ankit , Samuel Robello 
Published: January 2016

Abstract
Failures associated with drillstring vibration continue to occur, despite the use of risk quantification techniques based on vibration intensities and root mean square (RMS) accelerations. This paper introduces the concept of modified vibration stability plot as a practical tool to minimize and predict vibration. It integrates the modified vibration stability plot with a feature modeling data analysis tool to predict drillstring failures caused by torsional and lateral vibration.
The modified stability plot provides optimum operating parameters, including weight on bit (WOB), revolutions per minute (RPM), and rate of penetration (ROP), to minimize vibration. However, actual real-time drilling parameters are not always optimum. Consequently, the deviation of real-time parameters from the optimum values are used to calculate "deviation vectors" using statistical tools. These are then used to generate operating stability clusters to detect outliers in the drilling data that signify potential vibration events. Safe operating limits and operating times have been proposed by integrating the clustering technique with vibration risk index and cumulative vibration intensity plots to mitigate failures. The workflow has been applied to cases in which severe and moderate vibrations were encountered downhole and at the surface, respectively. Extensive simulations were performed to compare the data from downhole vibration sensors. The results show that the workflow closely predicts the occurrence of sustained vibrations before an actual downhole string failure event. Prolonged operations outside of the stability circle can cause failures, depending on the fatigue strength of the material. The occurrence of outliers outside of the stability clusters are calibrated with actual drillstring failures to correlate cumulative vibration intensity plots with the time duration of a vibration event. This calculation helps to define a vibration risk index that can trigger decisions to stop drilling or to change operating parameters before a failure occurs. The workflow also simultaneously predicts the dominant type of vibration in the system and in causing failures. The study concludes by providing guidelines to integrate the vibration stability chart with data analytics and explicates the significance of a statistics-based risk index to initiate real-time procedures to prevent drillstring integrity failure.
The workflow proposed and validated with case histories strives toward cost-effectiveness and increased productivity. This paper also implements data-driven techniques for risk quantification. The results and the method for determining a risk index and operational limits are robust, and can be applied as a starting point for other string configurations in similar downhole environments.
Advanced BHA-ROP Modeling Including Neural Network Analysis of Drilling Performance Data
Authors: Evangelatos Georgios I. , Payne Michael L. 
Published: January 2016

Abstract
Significant research on bottom-hole-assembly (BHA) vibrations in conjunction with continuous improvement in polycrystalline diamond cutter (PDC) bits using fluid mechanics has increased drilling efficiency and reduced related problems. Despite the analytical advances, most BHAs and bit – motor combinations are still heuristically chosen and most optimization efforts are by trial and error. The reason for this is the bit-rock interaction and the dynamics that the bit exerts on the BHA are stochastic processes, and most analyses use simplified assumptions for this complicated interaction. In this paper, numerical solutions for the differential equations describing the motion and dynamics of the BHA are provided including impact effects with the borehole while drilling near vertical wellbores. Secondly, the dynamics of this motion are coupled with a neural network model that is calibrated on previous bit runs. This approach renders significant improvements in predicting the performance of different bit-motor combinations and provides a reasonable estimation of ROP without having to actually run those combinations and re-calibrate the model. The main reasons why a strictly deterministic, numerical approach cannot be successful is that even though the BHA properties are well known and vibration characteristics can be estimated, the impact forces of those components with an imperfect bore hole with variable formation properties cannot be precisely calculated. In addition, the forces exciting the BHA – drillstring system through the bit are complex, multi-modal and semi-chaotic.
The neural network is hence used to identify and calibrate a model of the bit-rock interaction, essentially acting to partially de-couple BHA effects from how each bit achieves ROP. Several parameters affecting the drilling process are used as input and help uniquely identify the bit-rock interaction for a range of drilling parameters. This approach allows for a reasonable extrapolation of the bit’s behaviour on a different BHA and with different drilling parameters.
The Use of Wired Drillpipe Technology in a Complex Drilling Environment Increased Drilling Efficiency and Reduced Well Times
Authors: Schils Saskia , Teelken Reina , van Burkleo Brian , Rossa Ove Johnny , Edwards Nils 
Published: January 2016

Abstract
This paper presents and discusses the results of a case study where Wired Drillpipe (WDP) technology was implemented on the Martin Linge offshore field development project in the Norwegian sector of the North Sea.
Martin Linge’s resources consist of a shallow oil reservoir and several, deeper, structurally complex, high pressure gas and condensate reservoirs. The oil reservoirs are being developed with long horizontal wells and several deviated wells are drilled to unlock the gas and condensate reserves. The field was initially discovered in 1975 but proved too complex to develop at the time.
Over the years several exploration and appraisal wells were drilled within a narrow pressure window, with multiple BHA runs per section. The complex drilling environment posed many challenges including severe losses, influxes, unstable formations and excessive downhole shock and vibrations resulting in poor MWD/LWD signal.
WDP telemetry enables bi-directional, high speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al. 2008). Conventional telemetry methods only provide very limited bandwidth (8-12 bps) for real-time data transmission and can suffer from signal reliability under adverse conditions, for example: no mud pulse data transmission to surface when pumps off or at flowrates below tool settings, decoding issues during high levels of downhole shock and vibrations and unfavorable mud conditions, such as gelled cold mud, gas, high viscosity pills, mud additives etc.
WDP technology was implemented on the Martin Linge field development from the start of the development. The technology introduction cost off-set against the quantifiable benefits for the project was initially calculated close to break-even. Furthermore, the high upside potential associated with the use of this technology should allow improved well placement and have a positive effect on the quality of the drains drilled.
This paper will summarize how the high speed telemetry provided by WDP enables wells to be drilled without the typical limitations imposed by conventional telemetry methods. The analysis will focus on two areas of efficiency and performance improvement. Firstly, the quantified data transmission time savings due to the real time high speed transfer of critical data between downhole and surface will be discussed in detail. Secondly, the network performance, drilling performance, application of new technology and technology investment cost will be discussed.
Stuck Pipe Prediction Using Automated Real-Time Modeling and Data Analysis
Authors: Salminen Kent , Cheatham Curtis , Smith Mark , Valiulin Khaydar 
Published: January 2016

Abstract
A real-time method is presented to predict impending stuck pipe with sufficient warning to prevent it. The new method uses automated analysis of real-time modeling coupled with real-time data analysis. It can be applied to all well types for any well operation including drilling, casing running, completion activities, and re-entries. The method uses leading indicators of stuck pipe that were identified using historical data sets of 36 stuck pipe incidents in the Eagle Ford, Utica, Permian, and Gulf of Mexico. Four case histories show the utility of the new method in four shale horizontal wells for both drilling and off-bottom operations.
The new method combines two types of analysis: (1) deviation of real-time data from real-time model predictions using hydraulics and torque and drag (T&D) software, and (2) trend analysis (i.e., rate of change) of real-time data. Parameters used are pump pressure, flow rate, torque, rotary speed, hookload and drag, and weight on bit along with static inputs such as BHA and drillstring configuration and directional surveys. Additional parameters such as downhole ECD are used when available and improve the results. But the method is designed to monitor all well types and provide a stuck-pipe-risk log even using only basic instrumentation. A novel algorithm predicts the probability of stuck pipe which is presented in a real-time log.
Results demonstrate there is no single leading indicator present in all stuck pipe incidents. Consequently, relying on a single specific pattern (such as increasing pump pressure at constant flow rate) leads to inability to predict stuck pipe in some cases. Our early detection method relies on multiple indicators to strengthen the likelihood of detecting an increase in stuck pipe while avoiding false alerts. Deviations of parameters from model predictions have been used with success in the past by experts but the new method provides contextual awareness and provides thresholds that automate the process. A key element is the use of filtering for rig activity. Rate of change calculations provide valuable insight into rapidly deteriorating wellbore conditions when deviation from model predictions does not respond quickly enough over a short depth or time interval. The detection method was tested on four historical wells in which four stuck pipe and two near-miss events occurred. Testing showed that an alert was generated, on average, 38 minutes before the event. There were no false alerts recorded in these wells.
A Paradigm Shift in Well Control Training and Assessment
Authors: Denkowski Mark R. , Kelly Brenda G. , Garvin Mike 
Published: January 2016

Abstract
Human factors experts agree that about 80 percent of incidents in the oil and gas industry are the result of human error. Proper training and assessment is critical to reducing these incidents. Therefore, the upstream sector has implemented a program that represents a paradigm shift in well control training and assessment worldwide. This program focuses on the safety-critical knowledge and skills required for specific rig-based positions.
Members of the Well Control Committee of the International Association of Drilling Contractors (IADC) came together post-Macondo to redesign the well control training and assessment standard. They agreed to the following foundational elements of the new standard: five "levels" of training; curricula that are focused on the safety-critical job responsibilities of rig personnel; a standardized, proctored online knowledge assessment; enhanced use of simulation for individual trainees; clarified and enhanced instructor qualifications; and the expectation that trainees will complete the training and renew their credentials at the level appropriate to their job position.
The new standard requires trainees to be more engaged in the learning process and to undergo individual skills assessments. The knowledge-assessment database identifies specific knowledge gaps, allows instructors to review and close the gaps with each trainee before the completion of training, provides metrics regarding the alignment between the course taken and the trainee's job position, and affords analysis of instructor performance. Trainees have reacted positively to the new format and content and to the blending of theoretical and practical knowledge in the standardized assessment. Several unexpected benefits have been realized through this collaboration: 1) Development and implementation of the new standard is raising awareness of operational inconsistencies not only from company to company, but also globally. 2) Industry stakeholders can come together to find and agree on solutions and to address industry, public, and regulatory concerns. This effort represents a new kind of commitment to safety, one in which we hold ourselves and others accountable for the benefit of all.
When experts representing the primary stakeholders (operators, contractors, and industry trainers) came together voluntarily to develop and agree on this new standard, they were acknowledging that safety is a part of the non-competitive space of the oil and gas industry. Perhaps more importantly, they were acknowledging the significance of the human element in effective well control.
Avoiding the Money Pit: The Industrialization of Delivering Complex Drilling Facilities
Authors: Reid David , Yost Tom , Russell Ian , Cheung T. O. 
Published: January 2016

Abstract
Highly engineered, custom-built offshore platform designs begin with a simple plan to succeed based on managing complexity and risk, yet ultimately, the majority fail to meet the delivery, budgetary, and performance expectations that were identified at the beginning of the project. A significant amount of the Oil & Gas industry's largest facility undertakings were also discovered to fail in one, if not all, of the areas of hitting production targets. Those that were considered successful often achieved these results alongside documented longer deliveries and higher budgets from the outset, and very few that were discovered had best in class performance matching the development of Mobile Offshore Drilling Units (MODUs). This paper looks at the underlying causes of this phenomena and identifies patterns of execution and best practices for succeeding in an inherently complex construction environment. Two projects stood out and the best practices have been researched and compared to a third construction project with similar attributes, which are all discussed in Part One of this paper.
In Part One, the first two projects had well-defined relationships and outcomes and the third project suffered due to attempts to eliminate costs and a dysfunctional relationship between the driller, shipyards, and operator. All three projects were ultimate successes for the oil company. Part Two of the paper we look at the impact of the emerging practice of standardized drilling facilities that eliminates cost and complexity. We discuss in Part Three current drivers in our contracting model, and then Part Four introduces lessons learned from the recent build out of the MODU fleet. In the end, we will highlight how we as an industry can take advantage of the crisis of cost management in a low oil price environment. The theme of industrialization of the construction process is developed from the first two projects and carried into the MODU fleet, which implies that better performance is achievable and the overall complexity and cost of drilling facilities on platform rigs can become a reality.