bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenges and Solutions for Accurate Wellbore Placement in the Barents Sea
Authors: Mitkus Alexander , Maus Stefan , Willerth Marc , Reetz Andrew , Oskarsen Ray Tommy , Emilsen Morten Haug , Gergerechi Amir
Published: February 2019

As development of the Barents Sea continues with new plays such as the Castberg, accurate specification of the local magnetic field is important to reliably infer the orientation of the bottomhole assembly (BHA) in horizontal drilling. Since magnetic fields at high latitudes vary spatially and temporally, one requires both spatial models and a way to capture temporal changes. Large temporal changes in the magnetic field can severly distort measured azimuths and therefore must be corrected for.

This study, based on a report written for Petroleumstilsynet (Maus et al., 2017), shows that in regions of the Barents Sea within 50 km of a magnetic observatory, either the nearest observatory, interpolated infield referencing (IIFR), or the disturbance function (DF) method may be used for corrections in wellbore surveying to meet accuracy requirements. IIFR and DF will give better error reduction but are slightly more complicated to implement. At distances between 50 km and 250 km, the disturbance field (DF) method best meets accuracy requirements. In remote regions beyond 250 km, a local observatory must be deployed to meet the highest accuracy specifications, but the DF will still far outperform the other interpolated methods at such large distances from an existing observatory.

Despite having focused on the Barents Sea region, this comparison of the accuracy of different spatial and temporal magnetic field mitigation methods for wellbore surveying is applicable to high latitude northern and southern regions across the globe.
Customized High-Rate Cuttings Reinjection System: Effective Design Maintains Continuous Zero Discharge Operations on Sakhalin Island
Authors: Mahrous Ramy , Tsoy Vassiliy , Ellis Robert
Published: February 2019

Cuttings reinjection (CRI) is a globally accepted method for the disposal of drilling and production wastes, as it eliminates logistical challenges related to waste transport and storage, as well as the need for third-party disposal, which is often required by more conventional approaches. However, the CRI system must support penetration rates as high as 152.4 m/s (500 ft/hr). In arctic regions, the entire system must be winterized, while retaining ease of mobility for rig moves. Therefore, each CRI operation requires a customized design that correlates with drilling parameters, the local climate, and the scope of the drilling project.

On Sakhalin Island, an arctic area known for stringent regulations and a focus on highly optimized well construction, a CRI system was installed after intensive planning that accounted for the continued use of the original 2009 injection well, real-time cuttings collection in a winterized module, high capacities and process rates, continuous slurrification operations, and injection performed using cement pumps.

During a 14-month period, the customized CRI system successfully injected 95,867 m3 (602,988 bbl) of waste fluid from the six wells where the highest volumes were generated. The system delivered 100% operating efficiency throughout the project, keeping pace with the drilling activity, with a cuttings volume reaching up to 385 m3 (2,425 bbl) in one 24-hr period. Water-based cuttings and waste fluids from other rigs were also processed during this time. The system met all established performance criteria as outlined for the project's scope of work, including specified processing rates per hole section, slurries within specification, effective pumping schedule, and accurate and timely reporting.

Zero surface discharge projects present unique challenges that can be safely overcome with CRI technology. This paper describes essential steps in designing the site-specific system, best practices for managing sustained high-rate cuttings injection operations, and lessons learned concerning system optimization under harsh conditions.
Real-Time System to Calculate the Maximum Load of High-Frequency Torsional Oscillations Independent of Sensor Positioning
Authors: Andreas Hohl , Eric Palata , Pedro Arevalo
Published: February 2019

Cutting forces at the bit or mass imbalances in downhole tools such as mud motors can cause severe vibrations in drillstrings and bottom-hole assemblies (BHA). Negative effects include reduced rate of penetration, low-quality measurements and downhole tool failures. A value that represents the real downhole vibration level is needed to perform a reasonable mitigation strategy. The most common values are statistical values derived from acceleration signals that are received from a sensor at a specific distance from the bit (DfB). The interpretation of an acceleration signal is limited if only one mode shape is dominantly excited. In this case, the measurement signal is very sensitive with respect to the DfB of the sensor placement.

The derivation of a representative value for the severity of high-frequency torsional oscillation (HFTO) is shown that is independent of the sensor position. In the proposed approach, the dynamic torsional torque is used in addition to the tangential acceleration measurement. The frequency information of both measurement signals are determined and an analytical model is used to calculate the maximum value of vibration amplitudes that occurs along the BHA. The algorithm is implemented in the measurement-while drilling (MWD) tool for vibration and load measurements. The maximum load value in the BHA corresponding to HFTO can be sent to the surface in real time for interpretation by the driller.

In a case study, different scenarios from the field are discussed. The maximum load values are compared to numerical simulations that show an excellent agreement. The maximum value calculated by the approach is factors higher than the values measured by the accelerometers.

By using the algorithm-upgrade of the MWD tool, a representative measurement value for the severity of HFTO loads is derived. This is a clear advantage compared to tangential acceleration measurement only. The value enables the driller or an automated advisory system to initiate the optimal HFTO mitigation strategy that leads to reduced levels of vibration with the known benefits for the cost of a well.
Steering Advisory System for Rotary Steerable Systems
Authors: Zalluhoglu Umut , Demirer Nazli , Marck Julien , Gharib Hossam , Darbe Robert
Published: February 2019

The challenging offshore and shale production environments have increased the need for cost-effective, standardized drilling operations while providing accurate well placement and high borehole quality. Automation of directional drilling processes bears the promise of delivering these consistent and reliable performances while maximizing production potential. This paper introduces a steering advisory system for rotary steerable systems (RSS), which provides steering decisions automatically given the BHA configuration, bit selection, well plan and/or target(s), and real-time sensory information received from the RSS. These decisions can be either displayed to directional drillers or down-linked directly to the tool for autonomous directional drilling. The system has proven itself on multiple commercial jobs across North America with a new generation RSS. By exactly following the advisory system-generated steering decisions, multiple curve sections were smoothly drilled and accurately landed within tight tolerances.
Using High-Resolution MWD Survey Data in Mud Removal Simulations for Effective Cementing Program Design
Authors: Monterrosa Leida Cristina , Tay Chuang Hwee , Salazar Jose Martin
Published: February 2019

The main objective of this study was to understand the impact high-resolution measurement-while-drilling (MWD) surveys have on casing standoff and mud removal simulations and its impact on final cement program design and risk analysis.

High-resolution surveys use a combination of static and continuous MWD inclination data to characterize the well trajectory at 3-m (10-ft) intervals rather than the current industry practices at every stand; i.e., 30 m (100 ft). However, several case studies had demonstrated that surveying the well path at these intervals is often not sufficient to capture the true characterization of the well in question. This result, in some scenarios, leads to significant errors in the final reported dogleg severity (DLS) and tortuosity; therefore, resulting in optimistic well engineering simulations due the hidden additional tortuosity not applied in the models.

Two North Sea wells were analyzed when using conventional trajectories defined at each drillstring stand as well as using high-resolution trajectories to evaluate the impact on casing centralization and mud removal simulations.

The latest generation cementing software for placement simulation was used in this study. The simulation has the capabilities to deal with computing pipe standoff and angle direction in a 3D annulus, including gravitational forces for accurate mud displacement and removal.

This study confirmed that high-resolution MWD survey data can provide additional precise input for casing standoff and mud removal simulation, resulting in a more realistic simulation result due to the appearance of microtortuosity and DLS. Simulation results using high-resolution directional survey data identified conditions where the original mud removal assessment using a standard survey was overestimated due to higher standoff. This result allows an appropriate level of risk assessment and cement job design optimization to improve both the casing standoff and mud removal, which will eventually impact the well integrity quality.

This study proved that centralization and mud removal simulations can be, in some scenarios, optimistic if performed using standard trajectories. The results also proved that the risk assessments for the cement program designs will be evaluated differently because the enhanced simulations provide a more accurate result, which impacts the final centralization and mud removal to ensure effective zonal isolation.
Subsea BOP Tethering System as an Alternative for Mitigating Wellhead Fatigue
Authors: Sevillano L. Cantinelli , Morooka C. K. , Lieng J. T. , Sangesland S.
Published: February 2019

More-accurate estimates of the fatigue damage on subsea wellhead might prolong the service lifetime of the equipment. Nevertheless, there might come to a point during the life of a well on which the fatigue capacity is nearly depleted, without the possibility of further interventions being carried out, and thus imposing the abandonment of the well. This paper studies how employing a BOP tethering system may reduce the bending moment load transferred to the wellhead.

A BOP tethering system may be described as an assembly of anchors disposed around the subsea wellhead, which are connected to the BOP by mooring lines. The goal of the system is to reduce dynamic loads transferred to critical wellhead fatigue components and minimize the damage rates by decreasing the bending moment that is transferred from the riser to the wellhead.

The scope of a wellhead fatigue assessment comprises a riser response analysis. This paper presents the expected reduction on the calculated fluctuating bending moment load transferred to the wellhead for a series of possible configurations of the tethering system.

The results of the study conducted have shown that tethering the BOP system during drilling or re- entry operations has potential to decrease accumulated fatigue damage in the wellhead and can be regarded as an alternative for mitigating wellhead fatigue. The gains in petroleum production because of the increased operational life of the well have the potential to surpass the costs inherent to installing the tethering system. The results of simulations for different design options have shown the potential of this approach to increase the remaining service life of a wellhead, potentially doubling it. Even if installation restrictions prevent the optimum design to be used, this approach could still be advantageous.

Mitigating wellhead fatigue may prevent early well abandonment. Approaches considered to mitigate wellhead fatigue by actively reducing the load transferred to the wellhead have been presented before. The BOP tethering system is an alternative to these previous systems and provides operators an additional solution for consideration to their specific needs.
Revitalizing the Bakken With Managed Pressure Drilling
Authors: Parayno Gerard , Peacock Scott , Connolly Brandon
Published: February 2019

The operator has been very active drilling in the Williston Basin including the Bakken for several years now. As development progresses, lateral sections were steadily increased and are now in the 10,000ft range and with this, the average days in completing the section has also increased to 14 days. These wells have been drilled conventionally since the beginning of the campaign and have been plagued with problems such as stuck pipe, mud loses, pressure issues to cite some examples.

A test well was agreed for Managed Pressure Drilling (MPD) to see if this can solve the issues observed. MPD design for an optimized mud weight and surface backpressure schedule were utilized in the whole production section including for tripping and liner run operations. For the test well, a total of 9622ft of lateral was drilled for 7 days including casing run and cementing. Performance-driven application of MPD effectively reduced in half the operating days.

With the successful application of MPD, it has managed to achieve the main objective which is to reduce the operating days for drilling the production section. This was achieved through the ROP improvements due to a lower mud weight and application of back pressure to minimize surface gas and having the MPD package to handle the gas at the surface while drilling.

In the span of three months starting from that first test well for MPD, the campaign continued with using the technology and one more rig was added. So far 5 wells have been completed with improvements from MPD with reduced operating time. Lessons learned and continuous training of the field operating team have enabled for the drilling campaign to utilize this technique further in synergy with the other field service groups.

For this paper, the specific MPD operations will be described including the liner run procedures for the wells drilled so far and the key lessons for the continuous application of MPD to the Bakken drilling campaign in the Williston Basin.
Mitigating and Understanding Stick-Slip in Unconventional Wells
Authors: Dao Ngoc-Ha , Menand Stephane , Isbell Matt
Published: February 2019

Stick-slip is still present in most of the wells drilled today, especially in unconventional wells. Friction is an inevitable and important force along the long lateral section, but it contributes to many types of dysfunctions that lead to drilling inefficiency. Stick-slip is caused mainly by rotational friction induced along the drillstring, from the drill bit cutting the rock formation to the bottom hole assembly and drill pipe that contact the well bore. In the past, much attention has been given the cutting action of polycrystalline diamond compact (PDC) bits to explain and mitigate stick-slip, without much emphasis on the frictional torque. However, it is important to understand that the torque generated on the remaining drillstring accounts for most of the total torque at surface.

This paper presents a case study on an unconventional well where stick-slip modeling was used to explain and understand stick-slip vibrations with or without the presence of active control systems at surface. First, the stick-slip model, including a PDC bit law friction and accurate contact forces calculation along the drillstring and mud damping effect is fully described, with all necessary and field parameters needed. Then, it explains the process to reproduce and calibrate downhole and surface torque, using a sensitivity analysis showing the most important parameters that affect stick-slip results. The results reinforce the importance of drilling parameters, such as the weight on bit and associated torque on bit that define the bit aggressiveness and are key in controlling or mitigating stick-slip vibration. In addition, these results show the significance of string friction along the drill pipe. Next, the use of a downhole instrumented sub, along with wire drill pipe technology, enables a full comparison of the results of the model with downhole and surface data. Last, the affect of other parameters, such as friction coefficient and mud damping, are discussed.

With a better understanding of the initiation and translation of stick-slip from the bit up the hole to surface provided by this case study, engineers can be better informed when making decisions on factors such as drill pipe size and type, bit aggressiveness, and parameter changes in wells with severe stick-slip in unconventional wells application.
Application of Real-Time Fluids Data to Reduce Uncertainty in Casing-to-Casing Time
Authors: Jamison Dale , Williams Robert , Porter Aidan
Published: February 2019

Uncertainties in the drilling process result in safety factors or safety margins sufficient to minimize risks in the drilling process. These safety margins represent inefficiencies in the system. This paper will discuss a method for reducing uncertainty as it relates to well bore pressures and hole cleaning to eliminate or reduce these inefficiencies, quantify the rates of penetration that can be achieved, and illustrate the expected wellbore pressures generated by these rates of penetration.

When data is collected manually, the nuances of fluid changes are lost between property measurements. This paper will illustrate the difference between calculating equivalent circulating densities (ECD) with manually collected mud report data and fluid properties collected in real time and the impact that this can have on optimizing the rate at which the operator can drill and trip pipe.

A patent-based methodology will be presented, in which real-time drilling and fluids data are captured and utilized to model ECD pressure data related to the bore hole. The actual and modeled data are statistically analysed to infer information about how rapid a rate of penetration (ROP) may safely be employed to optimize drilling results.

Data will be presented demonstrating the impact that small improvements in fluid parameters and drilling operations can have over the course of drilling a well.

The role that a real-time hydraulics software model plays in providing predictive analytics for ROP optimization will also be discussed. Predictive analytics enable operators to look several stands ahead of the bit to determine if the ROP drilled will cause issues in the future. This enables the identification of the maximum ROP that can be drilled versus optimizing instantaneous ROP. This enables operators to optimize casing-to-casing time.
A Data Driven Approach to Predict Frictional Pressure Losses in Polymer-Based Fluids
Authors: Gul Sercan , Johnson Mitchell David , Karimi Vajargah Ali , Ma Zheren , Hoxha Besmir Buranaj , van Oort Eric
Published: February 2019

Managing drilling margins in challenging wells requires precise prediction of frictional pressure losses and equivalent circulating density (ECD). Current hydraulic models in the industry fail to accurately predict the frictional pressure losses of certain mud formulations in turbulent flow due to the complex behavior of long-chain polymer additives. These additives facilitate friction reduction in certain flow regimes. This reduction depends on several parameters, such as molecular weight and chemical composition of the polymers, making it difficult to quantify using existing models. In this paper, a data-driven approach is proposed to precisely predict frictional pressure losses for polymer-based fluids.

A flow-loop was constructed to measure frictional pressure-losses of several polymer-based non-Newtonian fluids under laminar, transitional, and turbulent flow regimes. Pressure loss data was obtained for fluids with different polymer concentrations at various temperatures using differential pressure measurement. A database of the experimental data was compiled and used to build a predictive model for frictional pressure prediction using advanced machine learning techniques. The proposed approach has general validity and can be extended to any type of well construction fluid (used in drilling, completion, stimulation, or workover).

Results for frictional pressure loss predictions from the proposed data-driven approach were compared with both the experimental data and widely used industry models. An excellent agreement was observed between the proposed approach and the experimental results, demonstrating the applicability of this approach for hydraulic modeling of polymer-based fluids. The improvements are particularly noticeable at higher polymer concentrations in the turbulent flow regime, where the average percentage discrepancy between the existing models and the experimental data can be as high as 45%.

The proposed approach in this study is particularly valuable for wells with a narrow drilling margin and concerns about the ability to manage ECDs (such as slim hole wells, deepwater wells or extended reach wells). It can assist with better planning and avoiding non-productive time and drilling problems such as lost circulation, stuck pipe, wellbore instability, and well control events. Its adaptability to a wide range of fluids using an expanded database makes it particularly attractive as a practical solution to this challenging problem.
A Drill Bit and Drilling Motor with Embedded High-Frequency 1600Hz Drilling Dynamics Sensors Provide New Insights into Challenging Downhole Drilling Conditions
Authors: Sugiura Junichi , Jones Steve
Published: February 2019

Drilling motors are typically used in every well drilled globally with conventional steerable bottom-hole assemblies (BHA's) and powered rotary-steerable BHA's. Downhole drilling dysfunctions are common when mud motors are pushed to the limit for maximum drilling performance. High-frequency (1600Hz) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box and top sub of the motor to better understand drilling conditions in different shale plays throughout North America land.

In the drilling industry, most downhole measurements for drilling dynamics utilize relatively low-frequency sensors (up to 100Hz). Typically, the measurements are burst and not continuous. These low-frequency burst acceleration devices cannot reliably measure high-frequency torsional oscillations (HFTO) which are known to be problematic while drilling in certain shale basins. Newly developed high-frequency (1600Hz) compact drilling dynamics sensors can now be embedded into the drill bit, mud motor bit box and top sub to record 3-axis accelerations continuously at high-speed sampling rates. The embedded sensors do not add any extra length to the steerable motor and therefore capture the true dynamic response of the system.

Embedding the high-frequency sensors at both ends of the mud motor provides two unique data sets of dynamic measurements. With conventional steerable motors and motor-assist rotary-steerable systems (RSS), HFTO dominant frequencies between 100 and 400Hz were commonly observed. In some cases, HFTO dominant frequencies between 400-700Hz and their harmonics were captured, which have not previously been reported. In most cases, the HFTO amplitudes are between 20 and 200g peak (or 40 and 400g peak-to-peak). On some occasions, ±200g self-perpetuating HFTO were recorded in memory where its calculated angular acceleration is more than 25,000 rad/s2.

The transitions between low-frequency stick-slip and HFTO were captured in high-speed recording. Negative string rotation speeds were commonly observed at the top sub of the motor while in rotary mode. It was noted that the bit would slow down to a stop but never turn backwards, resulting in the backward rotation of the motor top sub. During very high-amplitude multiple-axis shocks at the bit, it was discovered that there was a significant temperature rise due to loss of energy from bit dysfunction.

The newly reported drilling dynamics phenomena, such as multiple dominant HFTO frequency shifts, micro-sticks and micro-slips, will be detailed in this paper. Monitoring and understanding high-frequency drilling dynamics dysfunctions allows us to make systematic changes to bit, BHA and drilling parameters to reduce dysfunction magnitude and improve overall drilling efficiency and minimize component wear.
On the Sealability of Metal-to-Metal Seals with Application to Premium Casing Connections
Authors: Ernens Dennis , Peréz-Ràfols Francesc , Hoecke Dennis Van , Roijmans Roel F. , Riet Egbert J. , Voorde John Vande , Almqvist Andreas , Rooij Matthijn Bas , Roggeband Serge Mathieu , Haaften Willem Maarten , Vanderschueren Marc , Thibaux Phillipe , Pasaribu Henry Rihard
Published: February 2019

Metal-to-metal seals are used in connections of casing in oil and gas wells. This paper describes the mechanisms of sealing of metal-to-metal seals as investigated using an experimental set-up and a sealability model. Experiments were conducted for a variety of thread compounds and applied pin/box surface coatings. The results were used to validate a numerical model for sealability. The stochastic model couples a contact mechanics model with a flow model and takes the influence of all the surface topography features into account. Once validated, the model was used together with the experimental results to explain the sealing mechanisms of metal-to-metal seals.

The sealing configuration is a face seal with an R=80 mm round-off radius pressing against a flat. The face seal specimens were manufactured from P110 tubing. The used test set-up is designed for investigating only the metal-to-metal seal of the connection. The set-up can carry out rotary sliding under constant load to simulate surface evolution during make-up and subsequently perform a leakage test. The sealing limit is determined by applying 700 bar fluid pressure and then gradually reducing the normal force until leakage is observed. The data is subsequently used to validate a previously published model.

The results indicate a strong dependence of the type of thread compound used on the onset of leakage. The thread compound affects the amount of wear and thus changes the surface topography of the interacting surfaces. It is shown that the sealability model is capable to predict the onset of leakage within the experimental accuracy. The model shows further that certain surface topographical features improve the sealing performance. Namely, a turned against a flat surface topography leads to highly localized contact areas, which in turn yields the best sealing performance.

The combination of experimental data with the validated model leads to much deeper insights for the sealing mechanisms than what could be obtained using either on their own.
Rock Customized Shaped Cutters Improve Rock Cutting Efficiency
Authors: Rahmani Reza
Published: February 2019

Failing the rock and removal of failed rock are the two primary actions that control drill bit efficiency. A proper design must address both primary actions while focusing on the major efficiency driver. This has been the basis for development of shaped cutter technology where the geometry of polycrystalline diamond compact (PDC) cutter is designed according to the rock type.

Using the learnings from advanced modeling techniques on cutter-rock interaction, more than three dozen new geometries for PDC cutters were designed, manufactured, and tested. Based on the performance and application needs, three shapes were selected for further development: geometry A designed for shale applications focusing on efficient cuttings removal, geometry B for proper fracture initiation and propagation, and geometry C combines the features from the other two geometries to improve both creation and removal of cuttings.

The geometries were optimized for maximum rock cutting efficiency while maintaining the cutter durability via analytical and numerical modeling, and pressurized drilling tests, which are the focus of this paper. The cutters were then successfully tested in field applications with consistent good performance resulting in several performance records including in North America and the Middle East.
Industry's First PDC Bit Gauge Design for Improved Tracking In North American Horizontal Wells
Authors: Spencer Reed , Pierce Bradley D. , Grimes Robert E.
Published: February 2019

PDC bit gauge pad design parameters are well understood for providing the desired build up rate (BUR), but these designs provide minimal value in the horizontal section. Outside forces, such as bit walk and formation push, can cause deviations in inclination and azimuth. Trajectory corrections on both motor and RSS assemblies can significantly slow the drilling process and result in more tortuous wellbores. Thus, a PDC gauge pad design that provides minimal side cutting at low side loads, while achieving typical BUR at higher side loads should result in a PDC bit that tracks better with fewer unintended deviations and resulting trajectory corrections for improved overall drilling efficiency.

Prototype bits were developed with a tracking gauge pad design. Laboratory tests demonstrated the desired side cutting response at various side loads. Field tests are being conducted across the U.S. on pad wells offering direct comparisons to offsets using conventional PDC bits.

This paper presents the tracking gauge pad design concept, laboratory test results, and field performance improvements. Results show reduced trajectory deviations and dogleg severity, improving overall section ROP and hole quality.

Until now, the role of PDC bits has focused primarily on achieving the intended BUR and instantaneous ROP, leaving tracking performance solely to the drilling system. The tracking PDC gauge design concept breaks this paradigm by providing a PDC bit that tracks better than conventional bits for significant gains in directional drilling efficiency.
Computation of Surge Pressure Wave Propagation During Cementation Process
Authors: Assaad Wissam , Crescenzo Daniele Di , Murphy Darren , Boyd John
Published: February 2019

This paper presents a method of modelling surge pressures and wave propagation that can occur during well execution. The surge pressures have an impact on formations i.e. formation fracture resulting in mud losses and non-productive time. Knowing the amplitude of pressure surges in advance can lead to operation redesign to avoid losses. Pressure waves can occur at numerous points during well execution. For example, during liner operations, pressure waves can occur dart landing or plug shearing, liner hanger setting or clearing a plugged shoetrack component. It is possible that these pressure waves can create fractures in shale and sand layers i.e. when pressure wave amplitude exceeds formation fracturing limit.

A physical model is built to compute pressure wave propagation through drill string, casing and open hole, to predict amplitude of pressure wave and to warn when a fracture may occur in formation to avoid mud losses and non-productive time.

In the model, the continuity and energy partial differential equations are built for a cylindrical fluid element contained in an elastic hollow cylinder. Method of characteristic is applied to transfer the partial differential equations into ordinary differential equations. The ordinary differential equations are solved numerically to compute pressure distribution along well depth and in time. The physical model is implemented as a Graphical User Interface (GUI) tool to be used by drilling engineers at design phase of well to avoid losses. To date it has been used for cementing and perforating operations. Pressure wave computations are performed with the model for a field in Gulf of Mexico where mud losses have occurred, and results are presented in this paper.
Monitoring of Under-Reamer Function Status to Confirm In-Gauge Hole, Technology Validated by Open Hole Calliper: Case Study
Authors: Huggett Tom , Hunter Craig , Alahmad Mohammad , Eatough Oliver
Published: February 2019

Challenging conditions in a HP/HT well in the UK Central North Sea, led to the deployment of a contingent expandable liner. Under-reaming tools were needed to facilitate running of the contingent liner. Under-reaming operations are associated with a degree of uncertainty on the final hole diameter. A technology was deployed to monitor cutter position, wear and vibrations. With the aim of removing the above uncertainty. An open-hole calliper run was performed to validate the technology.

The monitoring system utilizes an arrangement of sensors to measure variables that are critical to under-reaming operations. The sensors are housed within the expandable cutting structure of the under-reamer and comprises of a cutter block position indicator and a PDC cutting structure wear sensor. The monitoring system can also record downhole dynamics at the under-reamer. The system can therefore determine, via memory data, the actual under-reamer extension size at any point during the run, therefore allowing the minimum hole diameter to be derived. Providing immediate feedback at the rig site once the tool is at surface.

The first run globally of the 12 ¼" × 14" size is presented, the monitoring system recorded 187 hrs of data. The cutter blocks position sensor showed the cutting structure was fully expanded as required whilst pumping at drilling flow rate once the tool was activated. The wear sensors were fully active and showed no wear for the duration of the systems battery life. A combination of the positional and wear sensors indicated full gauge hole to the recorded depth. Due to the type of contingent liner the delivery of gauge hole was critical. As such, the data was validated using a dedicated open-hole calliper run on wireline. The calliper confirmed the open-hole diameter calculated based on data provided by the wear and position sensors. Based on this result the requirement for an open-hole calliper run can be reconsidered. In addition, the acceleration recorded was well correlated with the MWD recorded vibration data and allowed parameter recommendations to be generated.

The ability to monitor the position and status of the under-reamer cutting structure eliminates uncertainty on the final hole size following under-reaming operations and identifies any problem areas and their probable causes prior to running casing/liner. In turn this has the potential to eliminate the need for wireline runs and therefore reduce the open-hole time in a potentially unstable formation.
Overcoming Challenges in an HP/HT Abandonment in the North Sea
Authors: Rublevskyi Anton , Reid James , Joneja Galen , Nafikova Svetlana , Salazar Jose
Published: February 2019

With the increase in decommissioning/abandonment work in the North Sea, a major operator had the objective to permanently abandon a well that had been temporarily suspended. There were several key challenges associated with this project: high pore pressure and temperature, a completion packer set in a target abandonment interval, and small cement plug volumes. These obstacles had to be overcome to complete the abandonment safely and efficiently. The primary barrier to the deepest potential flow zone, zone 1, was established by running flush slimline tubing through the 5-in. tubing and 9 7/8-in. production packer. The cement plug was then successfully placed below, across, and above the production packer. The cement plug was successfully tagged and inflow tested, creating a primary barrier against zone 1. This approach eliminated the need to remove the production packer prior to the abandonment plug being set, which saved the operator approximately 10 days of rig time. This paper outlines the detailed design preparations and presents the case history where these steps were implemented successfully.
A Paradigm in Rotary Steerable Drilling - Market Demands Drive a New Solution
Authors: Clegg John , Mejia Camilo , Farley Steve
Published: February 2019

This paper reviews how the Rotary Steerable System (RSS) market has changed over the last two decades. It explores current market forces; specifically the shift in RSS philosophy resulting from ever-improving motor steerable technology. It describes how the need for longer laterals with minimal tortuosity, maximum drilling efficiency, reduced risk of unplanned events, and elimination of AFE overspend, along with the paradigm shift in the directional drilling market seen since 2014, drove the specification for a new-generation RSS tool. The paper describes the development of a new RSS with a topology and control concept that allows full proportional control of bias from a fully rotating, push-the-bit tool, with the ability to "turn off" any bias during operations where side force is undesirable and to minimize potential tortuosity. It describes how the design team focused on modular design and rapid turn around of tools, in order to maximize utilization and efficiency. Field-test results are included, which demonstrate build and turn at up to 10°/100 ft. and the ability to drill accurate lateral sections. Field results also include the use of ultrasonic imaging while drilling to investigate hole quality.
Validation of Directional Survey Data Against Positional Uncertainty Models
Authors: Willerth Marc , Maus Stefan
Published: February 2019

Positional uncertainty is a critical component of managing collision risk while drilling. Ensuring that survey data meet the requirements of their uncertainty models has historically required complicated analysis. Most consumers of survey data are not experts and knowing when escalation is required in a high-risk situation can be unclear. This problem will increase as more data is evaluated by automated decision-making systems. Two novel methods are proposed to analyze sets of survey data against uncertainty models with the intent to answer the questions: "Is it safe to continue drilling" and "Does this wellbore need to be resurveyed?".

The proposed methods evaluate a survey set using the error sources, error magnitudes, and error propagations contained in positional uncertainty models. A quality control error covariance matrix is constructed, and the set is evaluated against it. Two statistical outputs are generated: a statistical distance that explains how well an additional survey fits with the existing survey data, and an overall survey assessment that describes the likelihood of an error-model compliant system producing the observed dataset.

The methods are used to evaluate downhole magnetic survey data that was flagged after evaluation by subject matter experts, but traditional quality control measures had failed to identify as problematic. Errors that do not fit the expectations of the error model are flagged in a way that is apparent to a non-expert user and can be integrated into an automated alert system. How to include these procedures in drilling workflows is discussed, including when escalation to a subject matter expert is required.

A system is proposed where, with minor modification to existing error models, this analysis can be automated for wellbore surveys of all kinds. Additional discussion is included on how these methods will fit into the upcoming API recommended practice on wellbore surveying.
Using Big Data to Study the Impact of Wellbore Tortuosity on Drilling, Completions, and Production Performance
Authors: Baumgartner Theresa , Lin Chris , Liu Yu , Mendonsa Aaron , Zimpfer Douglas
Published: February 2019

The principal indicators for drilling performance have traditionally been measures of time. For instance, time vs. depth and ROP serve as instant KPIs that are easy to measure and have obvious implications. Other potential performance parameters, such as the quality of the constructed wellbore are not considered in the drilling process. A standardized wellbore quality index has not been established yet. This work aims to narrow the gap between drilling and subsequent completion, production and plug & abandonment operations.

The operator gathered large data sets to link wellbore tortuosity with non-productive time (NPT) in drilling and completion and production outcome. A previously published measure of wellbore geometry, tortuosity index developed at the University of Texas (Zhou et al., 2016), was adjusted to better fit the requirements for the tortuosity study presented in this paper. Tortuosity values for horizontal, curve and vertical sections are calculated from about 2400 publicly available directional surveys for a basin in the US. The study uses data from hundreds of these wells to reveal correlations of tortuosity with drilling and completion NPT and correlations with production values in one out of three reservoir layers analyzed in this work.
Change Management Challenges Deploying a Rig-Based Drilling Advisory System
Authors: Behounek Michael , Millican Blake , Nelson Brian , Wicks Matthew , Rintala Eugene , White Matthew , Thetford Taylor , Ashok Pradeepkumar , Ramos Dawson
Published: February 2019

Sophisticated drilling analysis software is available to provide drillers with advice on setting and modifying drilling parameters such as WOB, RPM, etc., but getting a driller to accept the recommendations of the software is still complicated. Additionally, it is not sufficient that a driller on one test rig accept the changes to the drilling techniques and modified workflows. The challenge is to scale across an operator’s mixed rig contractor fleet getting fleet-wide driller and stakeholder buy-in.

The system used for this paper consists of a Rig-based Drilling Advisory System (RDAS) where new advisory information is displayed in the driller’s cabin running real-time pattern recognition algorithms to detect drilling dysfunctions. When a drilling dysfunction is encountered, a change in drilling parameters is suggested. Additionally, drilling parameters from offset wells are made automatically available for the driller’s use on the drilling screen. Through this process, we are entrusting the field personnel with a slightly higher level of technical responsibility. The team iteratively improved the system using feedback from drillers who used the RDAS.

Two rigs were selected for testing on how the drillers and the wellsite supervisors utilize the system. Feedback from these two rigs pointed to the need for customization on a well by well basis. Working through the on-site drilling engineers on the test rigs, modifications were then made to the system to fine tune how they wanted the drilling advisory to behave. For example, a wellsite supervisor wanted the system to ignore mild stick slip in a short drill section - a rigid system with no customization could not provide an adequate solution. Being adaptable helped to improve the acceptance, as the driller now started seeing the advisory more as a support tool. Agile software development was critical to success and the rig personnel appreciated the quick modifications to the system. This also gave them confidence in the process, and made them more responsive to change. Comparing drilling performance from wells before and after deployment provided a way to quantify the benefits. Seven total systems were deployed over a five month period. The operator continues to deploy to additional rigs until all active rigs are covered.

Change management is challenging. Many projects fail when this process is not properly executed. Presented here in detail is the process used by an operator to successfully implement a drilling advisory system across a mixed group of rig contractors. This process and the learnings presented in this paper serve as a case study for other companies embarking on such deployments.
Offline Cementing Technique
Authors: Urdaneta Javier , Wiriawan I Made , Barragan Gabriel , Curtis James , Casado Carlos , Schaefer Preston
Published: February 2019

The expansion phase of the offshore Mafumeira major capital project in Angola commenced in 2015. Because ofthe global low-oil-price environment, the team was challenged to revise the basis of design and operational procedures to help reduce well construction time by more than 50% and accelerate the date of first oil production.A major focus of this effort was to conduct as many offline activities as possible during the well construction.

Offline activities were performed before or after the jackup rig movedonto the slot, reducing the overall project cycle time. The feasibility of conducting offline cementing was evaluated and risk-assessed for several of the planned casing strings. The concept was conceived and implemented, initially for the 20-in. surface casings, for the second batch of wells in the expansion project. The ability to cement the surface casing offline allowed the rig to move to another slot and drill the next well in the batch campaign while simultaneously cementing, cutting the casing, and installing the wellhead on the previous well.

Nine tophole sections have been cemented in Angola using the offline cementing technique, providing USD 4 million intotal cost savings and reducing rig time approximately 18 hours per well, which helped achieve the overall target of reducing well construction time by 50%.The cementing objectives were successfully achieved in all cases, including adequate top of cement (TOC) and formation integrity tests (FITs) upon drilling out the shoes.

As part of continuous performance improvement, the opportunity to perform cementing offline in deeper hole sections of the well is being assessed.
Irreversible fatal contrast-induced encephalopathy: a case report
Authors: Zhao Wei , Zhang Jinping , Song Yun , Sun Lili , Zheng Meimei , Yin Hao , Zhang Jun , Wang Wei , Han Ju
Published: February 2019

Background: Contrast-induced encephalopathy (CIE) is a well-known complication of iodinated contrast agents during angiography and vascular interventions. It can manifest as hemiparesis, cortical blindness, speech changes, Parkinsonism, confusion, seizure, and coma. Most of the reported CIE cases have been transient and reversible. Irreversible fatal CIE cases have been rarely reported. All the fatal CIE cases reported involved the use of ionic high osmolar contrast agents. Here, we document a heretofore unreported fatal CIE after digital subtraction angiography（DSA）using iopamidol, which is a type of non-ionic monomer low osmolar contrast agent.
Case presentation: A 71-year-old woman was admitted to our Department of Neurology for paroxysmal buzzing of the brain. The cerebral magnetic resonance angiography (MRA) indicated the presence of arteriosclerosis of the cerebral arteries and bilateral stenosis of the middle cerebral arteries. The patient underwent DSA for further diagnostic work-up. The total amount of iopamidol used during the procedure was 110 ml. The patient experienced headache during the procedure, followed by dizziness with nausea and vomiting. Although the patient was treated with anti-oedema drugs, her deterioration was continuous. She gradually became comatose and suffered irreversible fatal cerebral oedema, which was confirmed by cerebral computed tomography (CT). Finally, the patient died 56 days after the procedure due to irreversible fatal cerebral oedema.
Conclusions: This report documents that iopamidol-induced encephalopathy may not always have a benign outcome and can result in irreversible fatal cerebral oedema.