bluuebunny/crossref_metadata_2025_split huggingface dataset:
Smart Wired Pipe: Drilling Field Trials
Authors: Macpherson John , Roders Ingo , Schoenborn Kai , Mieting Ralf , Lopez Fernando 
Published: February 2019

Abstract
Drilling systems automation requires a downhole digital backbone for closed-loop control, as do many other real-time drilling, completion and production operations. The absence of a reliable, high data bandwidth, bi-directional communication method between surface and downhole is a barrier to digitalization and automation of the oil field. This paper describes the development and successful drilling field trial of a micro-repeater wired pipe – effectively "smart pipe" – that removes this barrier.
The developed system uses battery-powered micro-repeaters (a fail-safe signal booster) placed within the box of each tubular and fully encapsulated dual RF-resonant antennas to transmit data between tubulars. The current system delivers 1-Mbps backbone data rate with a maximum payload of 720 kbps, and with a very low latency of 15 μsec/km, making it ideal for control-loop applications. The system design focusses on reliability: failure of multiple components will not affect telemetry. The prototype system has been rigorously field tested during drilling in Oklahoma.
Testing occurred on a drilling rig in Beggs, Oklahoma. The first trial (2016) covered drilling operations, the second (2017) covered controlling downhole technology; both were successful. The drilling trial demonstrated fitting the system to pipe with conventional API connections, standard rig-floor pipe handling, reliable wireless transmission between surface receivers and wired pipe network, the use of multiple along-string measurements of temperature and vibration, and simulated component failure. Of particular note was the surface system: it is wireless and no modification to the drilling rig was required.
Conventional tubulars can be refit with the system, which removes a barrier to the use of wired pipe for automation and LWD/MWD measurements in lower cost onshore operations. There is a benefit for drilling operations: all pipe joints contain a micro-repeater and are addressable for "smart pipe" applications such as an electronic pipe tally, and pipe condition monitoring. Drilling operations are the first users of the system, but it serves other operations, for example tubing conveyed wireline operations. The smart wired pipe concept is truly innovative. It enables drilling systems automation and logging-while-drilling applications, such as seismic-while-drilling with along-string sensors, by providing a fully open acquisition and control platform to the industry.
Unplanned Tortuosity Index: Separating Directional Drilling Performance from Planned Well Geometry
Authors: D'Angelo John , Ashok Pradeepkumar , van Oort Eric , Shahri Mojtaba , Thetford Taylor , Nelson Brian , Behounek Michael , White Matthew 
Published: February 2019

Abstract
Wellbore tortuosity is an important metric of wellbore quality; however, it is not always an appropriate reflection of directional drilling performance. Drilling planned tortuous features will increase wellbore tortuosity, but this in itself says nothing about directional drilling performance. Not only is there a need for a metric of wellbore tortuosity, it isalso necessary to have a metric of "unplanned" wellbore tortuosity. The former provides information about wellbore quality, whereas the latteris reflective of directional drilling performance.
The directional drilling literature contains metrics for both wellbore and unplanned tortuosity; however, they are largely unique and difficult to relate to one another. It is desirable for the planned and unplanned tortuosity metrics to be relatable. This would allow operators to not only quantify overall wellbore tortuosity in real time, but also to understand how much of that tortuosity is unplanned and possibly avoidable. This, then, opens up avenues for directional drilling performance improvement.
In this paper, a new metric, the "Unplanned" Tortuosity Index is developed on the basis of an existing metric of wellbore tortuosity. This is done by systematically removing the effects of intended tortuous features from the wellbore tortuosity analysis, retaining only those tortuous features in the wellbore trajectory that are unplanned. The unplanned tortuosity index is then tested on two distinct sets of survey data from actual wells drilled. The results are compared between the sets and with the wellbore tortuosity metric from which the new index was derived. It is shown that thenewly developed unplanned tortuosity index canhelp operators and directional drilling companies discern their directional drilling performance, especially forwell paths with multiple, planned tortuous features.
Mitigation of Multi-Frequency Stick/Slip
Authors: Sun Zhijie , Gu Qiuying 
Published: February 2019

Abstract
Stick/slip-induced vibration has been recognized as a cause for bit wear, premature tool failure, and poor drilling performance, which represents a contribution of approximately 30% of drilling vibration dysfunction. Dynamic modeling of stick/slip phenomena in drillstrings shows that the vibrational waves travel back and forth along the drillstring between the bit and top drive, which typically leads to 15% fluctuation in surface torque. It is also found that stick/slip is much more likely to occur with certain drilling fluid types and in deviated holes with large dogleg severity. One method of stick/slip mitigation is through control of the top drive. In existing applications, the vibrational wave at a fundamental frequency is absorbed by tuning a proportional-integral (PI) controller.
Stick/slip-induced vibrations do not exist at a single frequency, and the simple PI controller cannot mitigate stick/slip occurrence at all vibration frequencies. Vibrations at frequencies other than the frequency chosen for mitigation can be amplified using existing tuning methods. In tests in which the method was applied, there were cases in which the vibration shifts to the second mode when the first torsional mode is mitigated. Therefore, the challenge is to target more than one vibration frequency.
A new control system has been designed to observe stick/slip frequencies and then to dampen the stick/slip across a wide frequency range, while regulating the rotational speed of the drillstring at the desired set point. All control algorithms are implemented on a standard programmable logic controller (PLC). To eliminate the need to modify the existing top variable-frequency drives (VFD), this paper also proposes several methods to seamlessly implement the proposed controller.
Existing configurations and stick/slip mitigation tests based on PI controller-gained tuning have been achieved on a test rig. Field tests demonstrating the new control method have been performed, and the results are presented and analyzed in this paper.
Automatic Control of Mud Pumps, Draw-Works and Top-Drive on a Floater
Authors: Benoît Daireaux , Erik Dvergsnes , Eric Cayeux , Ronny Bergerud , Ivar Kjøsnes 
Published: February 2019

Abstract
The application of safe-guards, safety triggers and automated procedures to control the mud-pumps, hoisting system and top-drive allows for safer, more consistent and more efficient drilling operations. Attempting to apply drilling automation on a floater needs to manage the impact of the unpredictable movement of the drill-string induced by heave movements.
Because of the drill-string elasticity and the continuous movement of the rig, it is challenging to estimate the bit position, the bottom hole depth or the instantaneous rate of penetration. Yet, these estimations are crucial for the evaluation of cuttings production and their transport, or dynamic open hole pressures. Furthermore, the variability of the top of string movement can change abruptly when heave compensation is turned on or off or depending on the efficiency of the heave compensation system. These facts have an impact on the look-ahead strategy to determine safe drilling parameters.
An existing drilling automation system, originally designed for fixed platforms, has been modified to meet those new requirements. For this first adaptation, only vertical drilling has been considered. Heave movements with and without compensation are constantly monitored so that sudden or slow changes in amplitudes get accounted for. Induced effects on downhole pressures are estimated via hydraulic simulations for a wide range of drilling and heave scenarios. Consequently, the design of the automation system had to be deeply modified to incorporate this additional dimension. The resulting system has been used for the drilling of three exploration wells, in eleven sections.
Offshore drilling operations are characterized by a large variability of the drilling operation conditions. On a floater, the drilling context is even more challenging as it is subject to ever changing weather conditions. Yet, by utilizing model-based drilling automation solutions it is possible to improve drilling efficiency.
Intelligent Wellbore Path Estimation Using Multiple Integrated MEMS Sensors
Authors: Liu Huan , Shor Roman , Park Simon 
Published: February 2019

Abstract
To improve magnetic disturbance rejection and robustness of wellbore survey measurements, an adaptive neuro network-based fuzzy inference system (ANFIS) filter for wellbore position calculation is presented. This technique significantly improves magnetic disturbance rejection and reduces sensor error influence for borehole survey measurements. The new approach for the ANFIS filter is based on two redundant sets of IMUs which are located in different positions in the BHA at a known, constant distance. The distance between these two sets of IMUs will physically fade the effect of the magnetic disturbances. Each IMU set outputs position estimation based on the splines method which is then input into an ANFIS filter. The inputs of the splines calculation are azimuth, inclination angles and measurement depth, and the outputs are moving distance in three directions (Northing, Easting and True Vertical Depth). However, the accuracy of the splines method highly depends on the accuracy of the inputs, which are difficult to obtain during the measurement while drilling process even under pure clean environments (without any magnetic disturbances). Furthermore, the distorted azimuth caused by magnetic interference affects the borehole position accuracy. In order to deal with those problems, the designed ANFIS filter has a two-level structure. First a local level position estimation (splines method or well trained local ANFIS based on the sensor accuracy) for two sensor sets is used. If the sensor measurement accuracy is low, this local ANFIS will correct the position estimation. Then the outputs of the local modules were input into ANFIS for second level filtering (global filter) to remove the error which caused by unknown magnetic disturbances. According to the judgement of the ANFIS, the IMU set with the smaller magnetic disturbance is given greater weight to reduce the interference effect on the borehole position estimation. This two-level filter is compared to the traditional splines method under different tests situations. First, we evaluate this method by comparing with GPS positioning, from this test we know that the ANFIS filter shows a good performance when the magnitude of magnetic disturbance is within the training magnitude range. Even when the magnitude of magnetic disturbance is above the training range, the ANFIS filter shows a higher robustness than the traditional splines method. Also, this method was applied to borehole data with two IMU containing accelerometers and one magnetometer measurements. In order to apply our method, we duplicated one more magnetometer measurement data under magnetic interference for assessment. The results proved its magnetic disturbance robustness in borehole position estimation. Finally, we demonstrate the full potential using a laboratory experimental setup.
Concurrent Real-Time Distributed Fiber Optic Sensing of Casing Deformation and Cement Integrity Loss
Authors: Wu Qian , Nair Sriramya , Oort Eric van , Guzik Artur , Kishida Kinzo 
Published: February 2019

Abstract
Subsurface geomechanical changes can cause severe damage to oil and gas well casing strings and cement barriers, which can compromise the zonal isolation of either an abandoned or active well, in the latter case jeopardizing its productive life. A novel system was developed based on laboratory experiments to simultaneously monitor casing deformation and cement integrity using fiber optic distributed temperature and strain sensing (DTSS). The proposed system consists of a hybrid-Brillouin-Rayleigh-based DTSS technique used in combination with two dedicated fiber optic cables. The first is a standard telecommunication fiber, which is used to measure strain changes due to casing deformation. The second cable, coated with a hydrocarbon-sensitive polymer, detects an additional strain caused by the presence of hydrocarbons due to a loss of zonal isolation. The combined system can also detect temperature changes caused by formation fluid invasion from a lower depth into the cement annulus. Since the two cables will be installed side-by-side on the outside of a casing string within the cement sheath, the system can also be used for monitoring the quality of a cementing job. The proposed system provides continuous, real-time and in-situ monitoring of casing deformation and cement integrity to prevent substantial impact on production, or to detect plug failure and hydrocarbon leakage for abandoned and decommissioned wells. It can thereby provide detailed information (i.e. location, type, and event severity) to plan and execute remedial operations, if necessary.
Managing Drilling Losses in the Permian Using Airborne Gravity Full Tensor Gradiometry
Authors: Sallee Adam , Dick Hans , Sudhakar Vasudhaven , Morgan Alan , Payton Scott , Paddock David 
Published: February 2019

Abstract
Shallow drilling losses are a significant problem in the Permian basin because of the presence of subsurface karst features. Karst weakens the soluble rock producing voids and caves systems that result in drilling losses. An operator drilling in Culberson County, Texas recently experienced total losses drilling four surface holes in a pair of neighboring pads located in bordering leases. Drilling into caves negatively affected operations by reducing the drilled footage per day, increasing fluid and cementing costs, and increasing the difficulty in performing satisfactory cementing jobs to cover the water table.
This paper will describe the issues faced drilling with losses and explain how to manage the risk of losses by improving surface well placement with airborne gravity full tensor gradiometry (FTG) to map subsurface hazards.
Airborne gravity FTG measures the directional components of the gravity field. Multiple simultaneously acquired tensor components allow identification of anomalies associated with subsurface voids. For this project, a Basler BT67 aircraft acquired data over the targeted expanse with line spacing of 328 ft. The aerial survey took place over 3 days in July 2017.
Feasibility modeling using Castile formation cave systems reveals detectability of single caves larger than 10 m diameter with FTG, however networks of smaller caves are also detectable. Polygons created from analysis of negative vertical gravity tensor (Tzz) anomalies separate the cave systems into tiered risk areas.
Initial analysis reveals risk at both pads where losses occurred. Extending the analysis to the entire survey, the drilling events in the drilled offset wells match with the risk interpreted for karst. FTG data and subsequent interpretation offer strong correlation to known shallow hazards and cave systems, making it a useful tool for risk assessment. It recommended to locate future drill pads in the identified moderate risk areas and that any new wells be located away from elevated risk areas.
This is the first application of FTG to classify drilling risk of karst features in the Permian basin. The FTG hazard map improves operational integrity of surface location selection and is a complement to surface topography and geology considerations. The FTG data and analysis also holds promise for fault mapping and for water drilling efforts.
Subsea Xmas Tree and Completion Operations on Two Different Subsea Providers with a Single Rig Using One Common IWOCS System
Authors: Thibault Blanckaert , Arthur Bottomley 
Published: February 2019

Abstract
Offshore Congo West Africa, one of the subsea field developments has been installed with subsea production equipment designed and manufactured by two different subsea equipment suppliers. Therefore, it is a major challenge to be able to perform subsea intervention and installation with just one drilling rig being available on this subsea development as the subsea equipment from different subsea equipment suppliers is not design compatible. The conventional approach would be to change out the topside installation and intervention equipment from one manufacturer to that of the other on the rig. As this solution is far too expensive and time consuming, a need for one universal subsea installation and intervention system became an operational requirement.
This paper explains how one operator along with two subsea production equipment suppliers were able to design, manufacture and implement one universal drilling system refered to as –IDIMS (Interface for Dual Intervention Mode System). IDIMS increases the operational response while lowering the intervention cost on this field. Indeed IDIMS allows one single rig to intervene, drill and complete with two different subsea production equipment suppliers at a lower cost and with a shorter lead-time, which is a first in the oil industry.
For operators, IDIMS XT and TH modes represent a major innovation to reduce costs and drilling times in all subsidiaries with mature submarine fields equipped with different subsea production systems and equipment.
Over three years, this innovation allowed 107 MUSD of savings on this field.
The IDIMS concept could be reproduced and developed to intervene and drill on other subsea field developments with even more than two subsea production equipment suppliers. A single rig would then be able to operate on all of the subsea wellheads, tubing hangers, subsea XT installed/to be installed in one area, significantly reducing project development costs.
Tortuosity: The Rest of the Hidden Story
Authors: Samuel Robello , Zhang Yuan 
Published: February 2019

Abstract
Conventional methods calculate tortuosity based on the predetermined shape of the trajectory using the minimum curvature method; however, this discontinuity vanishes after the casing is run, and thus the well path becomes smooth. A fundamental flaw to calculate drag force, hook load, stretch, and casing wear using openhole surveys inside the casing is overestimation or underestimation of these values, depending on whether the torque-and-drag model used is soft or stiff string. This paper describes a mathematical formulation that considers flexural and torsional rigidities of casing pipes to estimate the vanishing tortuosity. It also presents research findings concerning the structural shape of wellbore tortuosity when combined with the data-driven approach from measurement while drilling (MWD)/gyroscope data, and an objective approach of smoothing using a new tortuosity calculation method.
Study of Formation Bonding in the Wells of the Varg Field Based on Ultrasonic and Sonic Wireline Log Data
Authors: Noble L. , Vindheim H. , Govil A. , Obando G. , Haga J. , Shams A. 
Published: February 2019

Abstract
This paper is based on the analysis of the ultrasonic/sonic data of the 9 5/8-in. casing logging of the 14 wells of the Varg field within the Norwegian Continental Shelf. While writing this papper Varg field was undergoing a plug and abandonment (P&A) phase after 19 years of production. High-quality bonding is observed behind the 9 5/8-in. casing far above expected theoretical top of cement within single casing areas. This bonding is attributed to the formation influence. Formation is used as an alternative to traditional cement barriers during P&A, and its use is regulated by the legislation.
The paper aims to develop better understanding of the mechanisms responsible for formation bonding development. The percentage of observed bonding at "high" and "high and moderate-to-high" quality is calculated within each well and is related to the various factors that could influence formation bonding development. Factors such as duration of time lapsed from well completion to well logging, type of well (producer versus injector), geological formation, type of drilling mud used, duration of production periods, volumes of production, and well deviation and azimuth were looked at to determine observable trends and relationships.
The results of the study allowed us to conclude which factors are critical or influence formation bonding. Based on the observations, recommendations can be made for the selection of the first well to be logged on the planned P&A campaigns. Correct selection of the first well saves time and resources on the formation testing for the qualification of the formation as a barrier.
Rigless Solutions to Well Intervention with Bismuth and Thermite
Authors: Carragher Paul , Fulks Jeff , McWilliam Gary 
Published: February 2019

Abstract
Excessive water production from oil and gas wells has long been an expensive problem to operators. Effectively shutting off this unwanted water production has been costly and largely ineffective, until now. By using a bismuth-based alloy and a chemical reaction thermite heater, there is an effective, rigless approach to shutting off unwanted water production that is also cost effective.
Previous methods for shutting off unwanted water zones typically involved setting multiple bridge plugs inside the completion. Although this baffled the flow of water, it did not stop it. The challenge was to isolate not only inside the completion, but in the annular space behind the completion to fully stop all water from the zone and do this all without the use of a rig. This has been achieved by melting a bismuth- based alloy with a thermite heater that is run on electric line.