bluuebunny/crossref_metadata_2025 huggingface dataset:
Pipe Sticking Prediction Using LWD Real-Time Measurements
Authors: Hess Joshua
Published: January 2016

In addition to formation evaluation, logging-while-drilling (LWD) measurements can also be used as a real-time solution to issues that arise during drilling. For example, LWD measurements can be interpreted to help determine if increasing mud weight is useful or if the rate of penetration (ROP) must be slowed. What if measurements made with LWD tools can help predict whether or not a drill string will become stuck while drilling? This paper describes a model that was created to predict situations with high risk of the tool becoming stuck so they can be addressed during the planning and execution phases. The model learns, or builds on each job experience, to improve future decisions.

Most experienced individuals involved in the drilling process understand the various ways that a drill string can become stuck and factors that contribute to it becoming stuck. Many variables are attributed to a bottom hole assembly (BHA) becoming stuck during drilling operations. This paper explains the variables that were used in the model and why they were used. Some measurable variables are wellbore characteristics, BHA characteristics, downhole pressure and temperature, drilling practices and mud properties. These variables were gathered from 42 wells drilled on the Gulf of Mexico (GOM) shelf. More specifically, the information was gathered from end-of-run reports, annular pressure (AP) logs, LWD databases and surveys.

After the model was created, the model was tested against seven additional GOM shelf wells. The model predicted correctly that in three of the seven wells, the drill string would be permanently stuck. In another three of the seven, the drill string was temporarily stuck while the model claimed it would be permanently stuck. In the final well, the model predicted that the drill string should be stuck, while it was not; however, the client made decisions while drilling the section which indicated that they were fearful of getting stuck.

If it can be shown that there is a risk of the drill string becoming stuck in a well, preventative as well as after-the-fact measures can be used to adjust the mud system and other drilling parameters. Additionally, fishing services can be prepared early or even moved to location earlier to cut down on non-productive time (NPT). A model such as this provides an indication of the need to try preventive measures to mitigate the situation before the problem occurs, or at a minimum provides additional information so that the best course of action can be taken.
A New On-Command Integrated Expandable Under Reamer Technology Enabled Unique Drilling Solutions: Lowering Operational Risks and Saving Operational Cost
Authors: Fang Lei , Manseth Arvid , Stue Kjell , Johansen Bjørn-Ståle , Skappel Jan Arild
Published: January 2016

This paper presents the technical features and the associated benefits of a new integrated expandable under reamer technology, and showcases the field testing of the technology in the Brage field at offshore Norway and the achieved results.

Historically, the overburden stratigraphy at Brage field has been challenging for drilling. The unstable green clay and Draupne shale formation, the casing and completion programs and Equivalent Circulation Density concerns associated with drilling extended reach wells necessitate hole enlargement while drilling. In particular, the 12 ¼″ section has a planned Total Depth (TD) right below the Draupne shale, inside which the calcite stringers also present, and a near bit reamer significantly increases the likelihood of getting down the 10 ¾" casing.

A new integrated under reamer technology was utilized to address the challenges in drilling five sections of a well in Brage: 14 ¾ ″ × 17 ½″, two 12 ¼″ × 13 ½″ sections and two 8 ½″ × 9″ sections. The new under reamer is fully integrated with the company's rotary steerable system, which enables unlimited on-demand activation and deactivation cycles through downlinking with each cycle taking less than 5 minutes, flexible and optimal placement of the reamer in the bottom hole assembly (BHA), and real time feedback from downhole. The flexibility of the placement in BHA allows the under reamer to be used as a near bit reamer, a main reamer, or both. When used as a near bit reamer, the reamer can reduce the rat hole length to a minimum of 4 meters in the same drilling run, eliminating the need of a dedicated rat hole elimination run. The real time feedback includes confirmation of the blade activation status and a hole opening diameter log, reducing operational uncertainties for under reaming and saving rig time for a shoulder test that is otherwise required.

The technology proved its effectiveness as a reliable main reamer as well as a near bit reamer for rat hole elimination while satisfying all requirements for directional drilling and enabling Measurement While Drilling (MWD) and Logging While Drilling (LWD) measurements. For the 12 ¼″ × 13 ½″ section, both main and near bit reamers were activated simultaneously while drilling the last 68 m to TD and a good drilling performance was observed from the run.

The new technology provides unique features such as unlimited cycles of activation and deactivation through downlinking, flexible placement in the BHA and real time confirmation of blade activation status and hole opening diameter. The paper will describe these features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost. It will also showcase a unique drilling application where three cutting / reaming elements in the BHA are actively present simultaneously and the associated drilling performance.
Statistical Analysis Between Different Surveying Instruments to Understand the Reliability of MWD/RSS High Resolution Surveys and its Effect in Well Trajectory Characterization
Authors: Monterrosa Leida C. , Rego Marina Ferreira , Zegarra Erica , Lowdon Ross
Published: January 2016

Industry standard practices for MWD surveying consist in taken the MWD surveys at the connection; this usually will represent 30-m to 40-m interval depending of the drill pipe range used by the operator or drilling contractor. Additionally, in some occasions, the surveying sample is even larger due other drilling operation considerations such as drilling through unstable formations or simply to save rig time by removing the amount of surveys taken in the well trajectory. However, several cases studies had demonstrated that surveying the well path at these intervals is often not enough to capture the real characterization of the well, leading, in some scenarios, to significant errors in the final True Vertical Depth (TVD) placement, less refined reservoir structure interpretation as well as well engineering simulations due the unseen extra tortuosity not applied in the torque and drag analysis.

A new technique, using a combination of static MWD or RSS surveys with continuous inclination, provides an engineering approach that allows describing the trajectory at 3-m (10-ft) interval thus reducing the risks aforementioned. This case study aimed to obtain further understanding of wellbore TVD placement and tortuosity characterization by qualifying the accuracy of the 3-m (10-ft) interval High-Resolution Continuous MWD surveys using statistical comparisons against micro-dogleg Continuous North-Seeking gyro listings as well as Dual Inclination analysis between MWD and Rotary Steerable Systems (RSS). TVD error analysis was also taken into account to explore how TVD error modelling can be optimized when considering survey frequency and the use of continuous inclination data in the Ellipses of Uncertainty (EOU) error terms.

The results and correlations did not simply ratify the fact that High-Resolution continuous surveys enhance TVD wellbore positioning and well engineering simulations, but more importantly it was possible to demonstrate that the standard deviations between independent surveying instruments at the same sample rate were small and well within the estimate position of uncertainty predicted by the current industry standard error models. Moreover, in order to deliver a more realistic TVD position the findings also outline the need of supplementary case studies with regards TVD error modeling optimization when using continuous data in the description of the well trajectory. Furthermore, this technique represents a step forward in real time decision making process in critical well placement jobs and will also allow drilling operations to be more efficient with reduced operational and HSE risks.
Solving the Casing Wear Puzzle Using Stiff String Model
Authors: Samuel Robello , Kumar Aniket , Gonzales Adolfo , Marcou Sylvester , Rød Anne Mette
Published: January 2016

As more and more complex wells are being drilled, an important problem to be addressed relates to casing, liner, and tubing wear. Casing wear is one of the continuing challenges faced by the industry, and an accurate estimation of downhole wear remains a paradox. Several casing wear estimation techniques were applied to actual drilling situations in the past; however, the results of those efforts have not always provided the necessary level of accuracy of wear prediction. The effects of improper estimation of casing wear may not be felt owing to the general overdesign of the casings by largely applying excessive casing-wear safety factors. This paper addresses these concerns by providing a comprehensive solution to this long-standing casing-wear puzzle.

The widely used conventional soft-string model is not applicable for all well paths for casing-wear modeling; it assumes that the drillstring continuously follows the exact wellbore curvature and cannot predict the different contact locations of the drillpipe with the inner casing wall. Consequently, a new modeling technique has been developed by applying the stiff-string model for casing-wear analysis. The stiff-string model calculates more accurate contact loads by accounting for the bending stiffness of the string and helps to estimate the contact position of the drillstring at any given casing depth. These contact points are used to model the development of multiple wear groove locations at any casing depth cross-section by accounting for the varying contact positions as various operations are performed through the casing. Estimates of multiple groove positions at each cross-section reduce the overestimation of casing wear, because the wear is now distributed across different grooves, thus providing a more realistic casing-wear estimate.

This modeling approach was validated by using ultrasonic logs from complex directional wells that are the most susceptible to wear. Detailed operational steps and parameters for each well were modeled to predict the development of multiple wear grooves for each casing section. These models were compared with the 360° cross-sectional distribution of remaining wall thickness from image-based ultrasonic logs. The estimated groove depths and positions correlated with the peaks observed from wear logs that showed the worst wear locations. The results obtained from this exhaustive analysis are promising to establish a new, more thorough means of validating casing-wear predictions. By applying a new comprehensive modeling approach using stiff-string analysis to estimate multiple wear grooves, this study has helped to reduce long-unsolved casing-wear uncertainties. A novel method for validating the estimated groove positions using the full 360° spectrum of caliper or ultrasonic logs has been presented. Accurate wear prediction is important for well integrity and optimized well designs.
Differentiate Drilling Fluid Thermal Expansion, Wellbore Ballooning and Real Kick during Flow Check with an Innovative Combination of Transient Simulation and Pumps off Annular Pressure While Drilling
Authors: Yuan Zhaoguang , Morrell Dan , Mayans Aldrick Gracia , Adariani Yahya H. , Bogan Matthew
Published: January 2016

To achieve a high level of drilling efficiency, it is paramount to correctly identify reasons of drilling events from available data in a timely fashion. Many surface or downhole events share common root causes. Drilling fluid thermal expansion, wellbore ballooning and formation kick share similarities in terms of surface observation such as pit gain volumes. However, resolution for each of them is completed in a totally different manner. Treating a wellbore ballooning effect in the same way as a kick will likely result in losing the current borehole after days or weeks of unsuccessful operations.

In this study, pressure while drilling technologies and software simulations are discussed to analyze variances in the wellbore parameters over time to investigate drilling fluid thermal expansion, wellbore ballooning and formation influx during flow checks in riserless drilling operations. A transient simulation software was used to study the fraction of gas in the annulus and fluid level inside the drillstring on several flow checks following flow and gas bubbles at the well head. Availability of continuous pumps off annular pressure while drilling measurement helps calibrate the simulations and verify its validity.

A new workflow combining modelling, simulations and downhole annular pressure profiling measurement was successfully applied to a riserless pilot hole deep water well Gulf of Mexico. The flow contribution from each drilling fluid thermal expansion, wellbore ballooning, formation influx and u-tube flow was identified and decomposed.

Transient flow simulator working together with pressure while drilling data gave the operator an exact knowledge of wellbore dynamics in an operation usually performed with limited information. This proved extremely valuable in the pursuit of drilling prospect.
Repurposing Proven HSE Techniques for use Outside Safety Reduces Non-Productive Time (NPT) and Improves Drilling Efficiency - A Case Study on Application of "Chronic Unease" to Improve Drilling Quality
Authors: Hurtado Manuel , Redlinger Thomas
Published: January 2016

Health, Safety and Environment (HSE) practices and regulations have been of paramount importance to the Oil & Gas industry for decades. Drilling operations represent a major HSE risk and therefore robust programs have been put in place by Operators and Service companies to minimize the risks and ultimately reduce incidents. The success and sustainability of these programs has been well documented with quantifiable results, but the techniques have been rarely expanded to other operational areas.  This paper reviews the field application of these HSE techniques on other areas of drilling operations and describes the results of the implementation over several years of offshore drilling experience. 

One of the HSE techniques used in this case study is known as "Chronic Unease", a state of mind that has been successfully integrated into safety programs to build a methodology based on the recognition (detection) and reaction to weak signals that could potentially lead to significant events. As such it presents strong similarities to the early detection of drilling risks that could be prevented through quality programs.

This paper re-introduces the concept of "Chronic Unease" and presents how it can be mapped to Quality Assurance and Quality Control techniques in drilling operations. It also reviews the field application of other HSE techniques and describes the results of their implementation in several case studies in offshore drilling operations. Ultimately the case study illustrates a correlation between drilling efficiency and the successful re-purposing of proven HSE techniques.
A Gear-Reduced Drilling Turbine Provides Game Changing Results: An Alternative to Downhole Positive Displacement Motor
Authors: Jones Steve , Feddema Chad , Sugiura Junichi
Published: January 2016

Drilling turbines, commonly referred to as Turbodrills, have historically been used for hard-rock applications in conjunction with diamond impregnated drill bits. Their use in North America land was typically restricted by rig stand-pipe-pressure limitations. Now, the latest generation rigs in North America land have sufficient stand pipe pressure to make use of Turbodrills.

Reducing the bit speed of a Turbodrill can provide significant advantages. Reducing the bit speed and increasing torque makes the Turbodrill suitable for a wider range of drilling environments, including high-temperature wells.

Turbodrills require no elastomer re-lines like Positive Displacement Motor (PDM) Power Sections, which are typically re-lined after every run in oil based mud. High-performance PDMs generate significant vibration which could reduce the life of measurement-while-drilling (MWD) systems. On the other hand, Turbodrills produce very little vibration, hence the life expectancy of bottom-hole assembly (BHA) components can be increased. Drilling with less vibration will lead to a more efficient drilling system and reduced non-productive time (NPT).

This paper describes the operation, flow test and field test results from a new Gear-Reduced Drilling Turbine (GRDT). Key component in the GRDT were instrumented to gather critical information on vibration, shock, temperature and rotation speed in revolutions per minute (RPM).
Use of a Transient Cuttings Transport Model in the Planning, Monitoring and Post Analysis of Complex Drilling Operations in the North Sea
Authors: Cayeux Eric , Leulseged Amare , Kluge Roald , Haga Jarle
Published: January 2016

Inadequate hole cleaning during a drilling operation may result in immediate problems such as excessive torque or pack-off situations, or it can lead to delayed problems such as while running in hole with a casing/liner or a completion string in a leftover cuttings bed. It is therefore desirable to provide quantitative information about hole cleaning conditions: at the planning stage, while drilling or when investigating incidents.

Because the ability to transport cuttings particles varies with their position in the borehole and the current drilling parameters, hole cleaning modelling is a history-dependent problem. The precise modelling of the movement of solid particles during a drilling operation gives the possibility to estimate whether they are in suspension in the drilling fluid, settling on the low side or being eroded from a cuttings bed. These estimations may be confirmed through the change of the active volume or by the increase of downhole pressure, when PWD (Pressure While Drilling) measurements are available.

A transient cuttings transport model has been used for planning and monitoring an ERD (Extended Reach Drilling) well drilled in the North Sea. The model has been used to compare the expected performance of different mud systems on both hydraulic and mechanical limits that could be expected prior to drilling. For another challenging drilling operation, the model has been used to post analyze the sequence of actions that led to problems while running in hole with a liner. Here also, the observations tended to confirm the predictions made by the hole cleaning model.

Furthermore, an active use of such an advanced hole cleaning model may help determine the time required for circulation procedures prior to pull out of hole. This can help reduce the flat time associated with circulation procedures and at the same time decrease the duration by which the hole stays open thus reducing the risk of hole instability.
Utilizing Short Bit-to-Bend Motor Technology Enables Monobore Wells to be Drilled in the Niobrara Unconventional Shale Play with a Single Drilling Assembly
Authors: Augustine Norwood , Jerde Brayden , Fleischhacker Curtis , Peterson Brian
Published: January 2016

The demand for reduced AFEs for horizontal wells drilled in the Niobrara unconventional shale play increased the need for improved drilling efficiencies. Better efficiencies can be achieved by utilizing monobore well designs which maintain a single diameter hole size for the vertical, curve and lateral sections, eliminating the need for an intermediate casing string and the subsequent need to change out drilling assemblies for a reduced hole size. Positive displacement motors (PDM) with short bit-to-bend technology (SBTB) enable the well to be completed with a single conventional drilling assembly.

To drill monobore wells in a single run, the following solutions were implemented: A positive displacement motor with SBTB and reduced adjustable kick-off (AKO) angle to achieve planned build-up rates and prevent component damage.Optimal motor output torque and speed for desired rate of penetration (ROP) and bit life.Drillstring and bottomhole assembly designed for improved drilling mechanics.Optimized drilling fluid program to maintain wellbore stability in challenging formations.

Each solution enablesfor the monobore wells to be drilled in a single run, which decreases the days on well by reducing time spent running intermediate casing and tripping for drilling assemblies.

This paper compares the monobore well design to the original well design utilizing multiple hole sizes by studying build-up rates (BUR), days on well, ROP and time spent tripping. The dataset used for this study comprises six single- conventional assembly monobore wells and six representative multiple-hole size wells. A consistent drilling efficiency improvement was apparent in the comparison.

This paper shows in detail how short bit-to-bend motor technology is an innovative solution to drilling the Niobrara unconventional shale play with a single conventional assembly.
Improved Wellbore Quality Using a Novel Real-Time Tortuosity Index
Authors: Zhou Yang , Zheng Dandan , Ashok Pradeepkumar , Oort Eric van
Published: January 2016

Tortuosity is an important metric in evaluating wellbore quality. A tortuous well path can lead to such well problems as stuck pipe, poor cementation, and early production equipment failure. The industry currently lacks a readily usable real-time tortuosity (density) index to enable the driller to make corrections during the drilling process. This paper presents a new algorithm to calculate the tortuosity index and validates the index using field data.

Until the last decade, average and maximum dogleg severity were the main indicators of wellbore tortuosity and quality. Recently, approaches which measure/model indirect quantities such as wellbore friction, bending moment, elastic energy etc. and then translate these to a measure of tortuosity, have gained popularity. However, such an indirect process introduces errors when the model used is not accurate. Another approach produces high precision 3D wellbore profiles to assist in ascertaining the tortuosity of the well. This method, however, requires additional downhole sensors at additional cost and a need for additional data-communicating and processing. To overcome these shortcomings, this paper proposes a methodology that is leveraging techniques used in medical field, more specifically in ophthalmology, to determine the tortuosity of the narrow veins in human eyes.

The methodology described in this paper produces a tortuosity "density" that has the ability to capture tortuosity at different length scales (from 1 foot to 10,000 feet). It works with conventional directional survey data and/or high-resolution survey as input and calculates a normalized number, the tortuosity (density) index, in real-time. The methodology was applied on the horizontal sections of 18 wells drilled in 2013 and 2014, and the tortuosity indices derived for these wells were compared against reports of drilling dysfunction and non-productive time. The tortuosity index correctly identified problematic wells that had multiple downhole equipment failures during drilling, and showed a strong correlation with other drilling dysfunctions.

The new real-time index provides a holistic view of wellbore tortuosity and may help to mitigate and correct problems before they occur. No new sensors or special practices are needed for the adoption of the method. This index is also robust to changes in survey distance, and provides an indication of micro-tortuosity when continuous/high-frequency gyro data is available.
Using Wired Drill Pipe, High-Speed Downhole Data, and Closed Loop Drilling Automation Technology to Drive Performance Improvement Across Multiple Wells in the Bakken
Authors: Trichel Donald K. , Isbell Matthew , Brown Bruce , Flash Major , McRay Michael , Nieto James , Fonseca Isaac
Published: January 2016

Many operators have developed optimization processes to reduce well delivery time and cost. These optimization processes typically include three basic performance improvement cycles: The first, the Real-time cycle, involves the management of drilling parameters to safely maximize penetration rate and drill bit run length with the drilling system currently in the hole. This cycle moves at a fast pace.The second, the Run-to-Run cycle, involves recognizing and reacting to the drilling system configuration needs based on performance during the run. These adjustments can only be applied to the following bit run or the same interval on a future well. This cycle moves at a slower pace than the first.The third, the Well-to-Well cycle, uses a detailed post-well analysis of performance trends and massive amounts of digital data collected over multiple wells to identify root causes of performance limiters. This knowledge is then applied to the drilling system re-design. This cycle is the slowest of the three.

To accelerate learning, the operator deployed a real-time, closed loop, downhole automation system (DHAS) in conjunction with wired drill pipe in the 8 ¾ in. hole section. The operator also used downhole memory tools in the 5 7/8 in. lateral section to collect downhole drilling parameters and vibration data. Our optimization process drew upon key elements from lean manufacturing concepts. It followed a Plan, Do, Check, Adjust (PDCA) loop, with the DHAS and the data provided by it impacting each of the three concurrently moving performance improvement cycles. The pilot test of the DHAS in the Bakken continued for 16 wells on four different surface locations, or pads.

Thirteen out of sixteen 8 ¾ in. hole intervals drilled with this system exhibited top quartile performance from a rig that had not drilled a top quartile well for over 2 years. As many as 45 hours of invisible lost time were removed from on-bottom drilling in a single hole section, compared to average performance in the same interval for the last three pads drilled with this same rig. Additionally, the operator identified previously unrecognized rate of penetration (ROP) limiters over the course of the project. The key limiter for the 8 ¾ in. vertical interval was a directional dropping tendency of the bottomhole assembly (BHA) which also limited the ability to mitigate the second key limiter, drill bit vibration. Off-bottom practices (e.g., reaming) limited performance for the curve interval. The key limiter for the lateral turned out to be tool failures, resulting from vibration events occurring during on-bottom and off-bottom transitions. The drilling team also learned how each of the performance improvement cycles is affected by the DHAS.
Along String Dynamics Measurements Reveal Isolated Potentially Damaging Upper String Vibration Environments
Authors: Cardy Neil , Hjortland Frode , Jeffrey Christopher , Wilde Simon , Muecke Nick , Wroth Andrew
Published: January 2016

While dynamics studies of drilling Bottom Hole Assemblies (BHAs) have been common since the introduction of downhole vibration measurement tools, little attention has been given to the dynamic environment in the upper drill string. By using distributed recorded mode dynamic subs both in the BHA and higher in the drill string, it has been possible to identify dynamic dysfunctions in the drill string that are not evident from BHA based sensors.

This paper examines offshore wells from the North West Shelf, Australia and the North Sea, which exhibit these potentially damaging vibrations. Data was collected from the downhole measurement tools and merged with surface data to allow the investigation of the BHA and drill string dynamic environments. In addition, high speed data bursts were investigated to understand the finer details of the dynamics. Modelling of the BHA and string to predict the critical vibration modes, resonances and contact forces was also carried out.

The analysis of the wells showed that while the bottom hole assemblies displayed very little torsional or lateral vibration; the upper drill string components were exposed to high energy lateral vibrations. The high energy lateral vibration environments were typically either bound by the rig drive system and contact forces between the drill string and the cased hole or between localized high contact forces in the upper sections of the well. Contact forces can isolate the drill string into distinct dynamic environments, potentially creating high energy destructive events in one section while relatively normal conditions are maintained in the other sections. These isolated drill string dynamic dysfunctions can potentially lead to accelerated drill pipe or casing wear with no obvious cause.

This paper shows how using distributed dynamics sensors throughout the BHA and drill string enables a detailed view of the drilling dynamics in the upper drill string, which previously has only been discussed theoretically. The study also highlights the potential risk for accelerated wear to both drill pipe and casing.
Remote Directional Drilling and Logging While Drilling Operations in the Arctic
Authors: Chatar Crispin , Stepnov Alexey , Mardyashov Anton , Gonzalez Juan Raul
Published: January 2016

Few locations present as many challenges as drilling in Arctic. It is one of the most hostile environments in the world. It contains some of the most remote locations, the toughest logistics challenges and the largest gaps in infrastructure on the planet. While the industry has moved progressively over the past decades to meet these challenges, one company's solution to reduce risk to personnel and the environment and to optimize cost was to do directionally drill and log the well remotely. Theoretically, wells could be steered and controlled from the comfort of your couch at home; millions of dollars' worth of technology controlled from thousands of miles away. With advances in data, communication and transmission technology, we have the capability to make it reality. This is exactly what was done.

The workflow is not only about monitoring or support from town offices but also a fundamental paradigm shift where the Directional Drilling and Measurement While Drilling (MWD) crew is not physically located on the rig. In order to accomplish this, a major transformation was needed to ensure that process safety was not compromised by introducing additional risk to the operation. Technologies had to be qualified and workflows had to be modified ultimately resulting in redefining roles and responsibilities. There was also a major challenge to convince operators to allow the control to come from a source external to the rig. There are many associated risks with such operations. These risks include loss of connectivity, untested methods for diagnosing tool failure and hardware failure to name a few.

In this paper the authors begin with a brief history of Remote Operations (RO) indicating major milestones. The challenges of implementation of RO centers, and the prevention and mitigation of the associated risks are discussed. Given the success in implementation of a major RO center in the Arctic, the methods and technologies used to achieve success is discussed with some specific focus on the Arctic operations. Many of the challenges and methodologies will be supported by details of implementation in the Arctic environment.
Prediction and Mitigation of Torsional Vibrations in Drilling Systems
Authors: Hohl Andreas , Tergeist Mathias , Oueslati Hatem , Herbig Christian , Ichaoui Mohamed , Ostermeyer Georg-Peter , Reckmann Hanno
Published: January 2016

Drilling systems are subject to torsional vibrations that are excited by bit-rock or by drillstring formation interaction forces. These torsional oscillations can be distinguished by mode shape and frequency. Well-known stick/slip oscillations are characterized by low frequencies (usually below 1 Hz) and affect the entire drill-string. High-frequency torsional oscillations (HFTO), in contrast, name the excitation of a high-order natural mode (reaching 400 Hz). In case of HFTO, the bottom-hole assembly (BHA) is exposed to high dynamics loads. Torsional vibrations compromise drilling efficiency and tool reliability. To address these challenges, we are proposing a method for automated BHA optimization based on mechanical drill string models.

Through extensive analysis of high-frequency (1400 Hz sampling frequency) data from field measurements, an analytical, verified, and easy to use criterion for the prediction of the excited torsional mode and the corresponding loads was derived. The criterion is based on the comparison of the resulting excitation from cutting forces at the bit and the damping of a torsional mode. The criterion is unique for every torsional mode and can be used to rank the susceptibility of torsional modes for HFTO or stick/slip.

A software application (Torsional Oscillation Advisor, TOA) has been developed for user-friendly interpretation of the underlying analytical method towards practical issues. The use of the TOA provides valuable input for drilling optimization: For stick/slip, the influence of various drill pipe sizes and the length of the drill pipe section on torsional stick/slip mode are analyzed. It is shown that the limit for stable drilling in case of bit induced stick/slip can be extended by stiffer drill pipes whereas the influence of the length of the drill pipe section is marginal. The material of the bit and its mass distribution is shown to have a considerable influence on the excitation of HFTO.

The software also enables automated BHA optimization in both new product development and tool operation phases. A numerical optimization approach is used to minimize the susceptibility of the bottom-hole assembly for stick/slip and HFTO for given constraints of the geometry and material parameters. Herein, a significant increase of stable drilling conditions regarding weight on bit and bit rotational speed with respect to torsional oscillations is achieved. Even small changes in the drilling system design have a visible impact on the torsional stability. The ability to identify and predict modes of stick/slip and HFTO that are most likely to be excited while drilling, an extension of the stable drilling zone and the estimation of loads before field deployment will result in higher drilling efficiency, more reliable tools and lower non-productive time.
The Anatomy of High Performance Float Equipment and Potential Failure Modes
Authors: Farley Douglas , Barannikow Ivan A. , Bourg Brandon L.
Published: January 2016

Float equipment comes in a variety of configurations incorporating such devices as poppet float valves and flapper valves to prevent cement from re-entering the casing at the end of displacement. Autofill functionality can be achieved by using various methods of flow and ball de-activation to either increase trip speed or reduce surge pressure on the formation. Float equipment performance is now loosely defined by the recommended practices in API RP10F. With the pending introduction of newly proposed API 10F standards, the industry recognizes the need to better define the performance properties for flow endurance, temperature, and back pressure. However, this much needed and improved specification does not address drillability and plug bump ratings.

This seemingly simple technology has highly engineered nuances that may not be readily apparent. The careful balance of flow endurance, high pressure resistance, and debris tolerance while maintaining quick drill-out properties has been achieved through many years of refinement and testing. Even the concrete used in the manufacture of float equipment is highly engineered to provide ultrahigh compressive strengths and shear bonding, which not only create a drillable product but also produce a seal between the steel hull and the valve. If these nuances are not clearly understood, the selection of high-performance, cost-effective float equipment can be compromised, which can lead to poor cement placement, remedial intervention, added drill-out costs, and reduced well integrity. Failure modes are often attributed to design flaws or manufacturing errors. In some cases this is accurate, but a detailed understanding of performance properties and accurate compressibility calculations can mean the difference between allowing sufficient flow back and recording a float failure. Pipe management and standardized cementing practices are also important to success.

This paper will explore the design practices and manufacturing methods for various types of float equipment and the need to dovetail the newly proposed API 10F standards and future iterations into the selection criteria for cost effective, reliable float equipment. This discussion will also review reasons for float failures and the causes behind these incidents.
Automated Drilling Fluid Analysis using Advanced Particle Size Analyzers
Authors: Oort Eric van , Hoxha Besmir Buranaj , Yang Lin , Hale Arthur
Published: January 2016

The era of drilling fluid property analysis carried out manually by a mud engineer is rapidly disappearing. Novel measurement tools and techniques are now making it possible to carry out sophisticated drilling fluid analyses using largely automated equipment. This paper anticipates and highlights the important role that automated particle size analyzers will play in future drilling operations.

A comprehensive experimental study was carried out using a new generation of particle size analyzers (PSA) to investigate their utility for automated drilling fluid analysis. The pieces of equipment that were evaluated were the Canty Microflow LPA (which uses imaging microscopy), the Mettler Toledo G400 ParticleTrack (which uses FBRM laser diffraction) and the Malvern Mastersizer and Zetasizer (which use Dynamic Light Scattering). These instruments were used in conjunction with in-house flow loops and shearing facilities to test (1) degradation of the particle size distribution (PSD) of lost circulation and wellbore strengthening materials under the influence of shear, (2) the behavior of the emulsion droplet size distribution (DSD) of invert emulsion mud systems (oil-based and synthetic-based muds).

Verifying and maintaining the PSD of lost circulation/wellbore strengthening materials is of crucial importance to prevent severe mud loss events that still continue to plague the industry at a trouble cost of many billions of dollars per annum. Our PSA analyses show that the PSD's of such materials, particularly those of medium to coarser sizes, is far from stable and degrades over time, primarily due to the influence of shear. It will be shown that automated, in-line PSA equipment allows for the degradation to be monitored and managed in real-time to maintain optimum drilling performance. In addition, such equipment can be used to monitor and optimize the DSD of an invert system, which is an extremely important quantity that influences many mud performance characteristics such as rheology, emulsion stability, fluid loss behavior, osmotic membrane efficiency, etc.

The work involves a comparative study of novel PSA's, ranking them by accuracy, ease of use, automation potential, real-time monitoring capability etc. It presents novel, non-intuitive data on the degradation of lost circulation/wellbore strengthening materials, thereby allowing ways to manage this degradation. It also presents, for the first time, some preliminary work on the behavior of invert mud droplet size and its impact on oil-/synthetic-based mud performance.
Multi-Zone Intelligent Completions for Interference Test Data Gathering Onshore Kenya
Authors: Ure John , Peytchev Peter , Jha Mihir , Wenk Andrew , Mackay John , Anuar Fendi , Asbey Thor
Published: January 2016

The operator is involved in the exploration and appraisal of the South Lokichar basin in the Turkana region in remote north-west Kenya. The fields so far discovered are characterised by multiple pay zones spread over sand/shale sequences of 800 – 1,000m in thickness, with the shallowest reservoirs at approximately 850 – 1,200m true vertical depth below ground level. Well total depths are in the range 2,300 – 2,500m measured depth below rotary table. Productive hydrocarbon-bearing zones to date have been sub-hydrostatic in initial pressure. The reservoir fluid is a waxy crude oil (24 – 37% wax content) with low, variable gas-oil ratio. Flow assurance is a key aspect of the completion design, due to the reservoir temperature of the shallower prospective zones being close to the wax appearance temperature.

Until late 2014 the drill stem testing of discovery and appraisal wells was rig based. Productive zones were tested in a ‘bottom-up’ sequence resulting in durations of 50 – 60 days for a five-zone drill stem test. The initial aim of well design activity was to increase testing operational efficiency, however the operator accelerated the area development planning as a result of the exploration and appraisal drilling success in the basin. Subsequently, completion design efforts were driven to meet a subsurface requirement for the acquisition of well test and transient interference pressure data from extended well testing involving five wells in two of the discovered fields (Amosing and Ngamia). The approach which has been successfully implemented, was to make all well testing rigless after the installation of a multi-zone intelligent completion, allowing the rig to continue appraisal drilling or well completion activity in parallel with these testing programmes.

This paper presents the completion design selected and the operational challenges which have been overcome by the operator in appraising these fields.
Improved Drilling Performance in Extended Horizontals Using Clean Brines in the Williston Basin
Authors: Davidson J. , Thompson B. , Dearing H. , Jones C. S. , Shipman J.
Published: January 2016

The successful drilling of an oil and gas well relies upon the application and maintenance of innovative technology. In order to improve drilling efficiency, all pertinent data needs to be reviewed appropriately and lessons learned need to be drafted and realized. This is particularly important with challenging extended-reach wells. Due to the very low permeability in the target formation, long horizontal laterals are desirable to improve oil recovery and maximize productivity. Long lateral lengths are limited by frictional losses from torque and drag. In this environment, a drilling fluid that is able to maintain low lubricity coefficients is required. In addition, the fluid must be environmentally sound and cost-effective. An underbalanced high-performance brine drilling fluid (HPBDF) was introduced as an alternative to the weighted oil-based fluid required in use.

As expected, different fluids require different strategies. When using a HPBDF, monitoring lubricant concentration and use is best practice. Using field measurements to adjust concentrations, the desired lubricity was achieved and maintained while minimizing lubricant use. Low lubricity coefficients correspond with reduced pipe wear and decreased torque and drag. By planning, monitoring and maintaining the HPBDF, the operator successfully achieved higher rates of penetration (ROP) resulting in shorter drilling times. In this application, low viscosity brines improved wellbore cleaning due to turbulent flow cuttings transport. This reduced time spent on clean up cycles and tripping times as compared to offset wells drilled with oil-based fluids.

The brine density eliminated the need for barite and minimized the solids in the drilling fluid. Suspended drilled solids in the HPBDF can increase abrasion and lead to increased torque and drag and directional tool wear and failures. When solids accumulated in the HPBDF, a dewatering system was used to flocculate the solids and remove them through a centrifuge to produce clean brine. Techniques were improved to provide clear brine while minimizing lubricant loss. For example, application of a high-performance fluid conditioner prevented lubricant loss in the dewatering process.

This paper discusses the use of HPBDF in drilling over 50 wells and the challenges overcome. It also details the equipment used and highlights the comprehensive technique for evaluating lubricity and its correlation to torque and drag. The resulting performance improvements reduced drilling costs by over 20%.
Multilaterals in the Mississippi Lime
Authors: Meize Robert , Reid Lance , Dano Frank
Published: January 2016

Resource plays are constantly challenged with ways to reduce costs and cycle times. The Mississippian carbonate reservoir offers thickness and rock strength, together with stacked pay conducive to multilateral techniques and their inherent cost savings. A multi-disciplinary team has drilled and completed over 25 multilaterals of various configurations, validating the mechanical feasibility, along with associated cost and production benefits. This paper presents details on operational techniques needed to successfully build the multilateral wellbore, pros and cons associated with the different concepts and some of the initial cost and production results.

Open-hole sidetracks along with cased-hole whipstocks are used to initiate the multilaterals. The reservoir requires stimulation, which necessitates running a packer and sleeve system typically run on a 4-1/2″ liner. After stimulation, the casing is cut-off in the open hole leaving each leg open to the multilateral junction to produce into a common wellbore.

Over 25 multilaterals have been completed with 100% mechanical success. Directional techniques and completion systems make this a viable alternative to single well laterals enabling cost reductions on a field-wide development. These cost reductions provide needed benefit, especially in a reduced oil price environment.

SandRidge Energy, Inc. started work in the Mississippian play in Oklahoma & Kansas beginning in 2009. The use of horizontal drilling techniques in this mature carbonate reservoir together with an aggressive infrastructure strategy has led to over 1,200 horizontal wells being drilled. The multilateral program is ongoing, so additional production information and results will be shared as it becomes available to the public.
Design and Performance of Annular Pressure Build-Up APB Mitigation Techniques
Authors: Sathuvalli U. B. , Pilko R. M. , Gonzalez R. A. , Pai R. M. , Sachdeva P. , Suryanarayana P. V.
Published: January 2016

Subsea wells use Annular Pressure Build-up (APB) mitigation devices to ensure well integrity. Type I mitigation techniques control APB by reducing radial heat loss from the production tubing to the wellbore. Type II techniques work by controlling the stiffness (psi/°F) of an annulus by modifying its contents and boundaries.

Though the physics of APB mitigation is well understood, the reliability of a mitigation strategy or its interaction with other parts of the wellbore is not always quantifiable. This is partly due to lack of a unified approach to analyze mitigation strategies, and partly due to lack of downhole data after well completion. Simply stated, the engineer is hard pressed to find computational-predictive methods to assess alternative scenarios and strategies within the framework of the design basis during the life of the well. In this light, our paper presents a quantitative approach to design the currently used APB mitigation strategies, i.e., rupture disks, syntactic foams, nitrified spacers, and Vacuum Insulated Tubing (VIT). In each case, the design is linked to the notion of “allowable APB” in an annulus, which in turn, is tied to the design of the casing strings, and thus to wellbore integrity. Based on an extensive survey of published literature and patents, we also review APB mitigation techniques that have been used less frequently or awaiting proof of concept/field trial.