bluuebunny/crossref_metadata_2025_split huggingface dataset:
Casing Wear Factors: How do They Improve Well Integrity Analyses?
Authors: Kumar Aniket , Samuel Robello 
Published: March 2015

Abstract
Casing wear factors form an integral part of casing wear estimation techniques. However, the values of experimental wear factors do not match field conditions when predicted casing wear is compared to measured values. Hence, adjustments and manipulations are made to wear factors to match field data so that these calibrated values can be effectively applied for more accurate predictions. These field calibrations, which often are extensive, have resulted in casing wear factors being mainly treated as just “fudge factors.” This has led to a lot of confusion regarding the fundamentals behind using wear factors for casing wear analyses.
This paper aims to bridge this knowledge gap and provides a comprehensive treatise on casing wear factors and their underlying parameters. The paper describes the details, a clear definition, uncertainties involved, and concepts regarding the appropriate use of casing wear factors and their applications. The wear factors are inherently tied to the coefficient of friction or the friction factor, which in turn is also a proxy because of the larger uncertainties involved in the modeling process. Wear factor values are also dependent on the material properties and operation type and vary non-linearly with the wear groove shape. Additional variations in experimental values also arise resulting from downhole high-pressure/high-temperature (HP/HT) conditions, accuracy of well surveys, as well as wellbore tortuosity and torsion. Other operating parameters, such as rotational speed, rotating time, and normal contact force, can also influence wear factors.
This paper investigates, in detail, the dependency of casing wear factors on these uncertainties through several example case analyses. It provides detailed explanations to help understand the fundamental concepts and apply appropriate wear factors for accurate downhole wear estimation. Accurate prediction of casing wear is essential to enhance well integrity and further the life of the well. Hence, this paper also presents a specific example for casing integrity analysis and provides insights to improve overall well integrity by performing a comprehensive casing wear analysis. In addition, the concept of casing wear maps is introduced. These can provide a new visualization and interpretation technique and help to minimize casing wear during drilling operations.
Accurate casing wear prediction is crucial for helping to reduce the over-engineering of casing designs in increasingly complex drilling programs, as well as for helping to prevent catastrophic casing string failures caused by wear. This paper provides a sound engineering basis for future drilling engineers to effectively understand the challenges involved in selecting appropriate wear factors and the underlying uncertainties that govern casing wear estimation analyses.
Advances in the Calculation of Circulating Pressure Drop with and without Drillpipe Rotation
Authors: Hemphill Terry 
Published: March 2015

Abstract
Annular pressure measurements have consistently shown the direct relationship between increasing drillpipe rotation speed and increasing pressure drop. A hydraulic model that accurately predicts the hydraulic effects of drillpipe rotation can improve the pressure drop calculations. However, conventional pressure drop modeling does not take into account 100% of the calculated pressure drop that is produced with the drillpipe rotation moving the fluid in helical flow. Hence a need to better refine calculation methods is warranted.
The pressure drop calculations for flowing drilling fluids were calculated using equations previously published. Calculations for axial and helical flow were performed separately, as in the axial flow case an area of plug flow is assumed, while in the helical flow case 100% of flow area is assumed to be sheared.
Conventional pressure drop modeling uses geometry, pump rate, and drilling fluid rheological properties to calculate pressure drop across the annular gap. However, these results usually account for approximately 95% of the real pressure drop. What has been missing up to this point is the pressure drop that arises between the slipping fluid layers moving in helical flow. Secondly, the effects of drillpipe rotation are usually not taken into account, even when the drillpipe is rotating.
Theoretical calculations using the proposed solution for total pressure drop show that: 100% of the pressure drop can now be theoretically accounted for, both with and without the effects of drillpipe rotation.With drillpipe rotation taken into account, the pressure drop in the slipping fluid layers is higher than that for axial cases. A method is shown that explains how to calculate this extra pressure for both axial and helical flow cases.Pressure drops in eccentric geometry cases can rise quickly in the more-narrow annular regions. Hence when drillpipe rotation speeds are in the normal operating range of ±100 rev/min, calculated pressure drops approximate those calculated conventionally (axial flow with no drillpipe rotation).
With these extra pressure drop calculations, the real pressure drops for fluid moving in helical flow can be obtained, something especially important in areas where safe drilling window margins are very narrow. As a result, better equivalent circulating density (ECD) predictions can be made.
Managing Losses in Naturally Fractured Formations: Sometimes Nano is too Small
Authors: Savari Sharath , Whitfill Donald L. 
Published: March 2015

Abstract
Controlling severe to total loss situations in naturally fractured and unconsolidated formations can be critical and, most of the time, these situations make it difficult to continue drilling. Conventional lost circulation materials (LCMs), such as ground marble, graphite, and nutshells might not work. In such situations, the operator generally resorts to using cement plugs or mud-cap drilling.
This paper presents novel applications in the form of engineered composite LCM solutions (ECS) successfully used to manage severe to total loss situations in naturally fractured carbonate formations. Case studies are presented from applications in North America, the Middle East, and East Africa. Engineered multimodal (MM) LCMs, which are composite LCMs with MM particle-size distribution (PSD), were developed as remedial solutions for handling severe to total losses. The MM PSD is characterized by a PSD curve with two or more concentration peaks, which help better manage uncertainty in fracture sizes. The particulate ECS was extensively tested in the laboratory for its effectiveness in terms of plugging large slots. For the most severe lost circulation cases, a combination of two ECS materials, one containing a swellable component, is proposed as a potential solution.
While drilling a severely fractured limestone formation in North America, the combination of particulate and swellable ECS, along with chopped fibers, was applied after all conventional LCM applications failed. The combination was pumped open ended and losses were totally cured, allowing circulation to be established again. With this experience, similar solutions were included in the plan for drilling a highly fractured carbonate formation for an operator in the Middle East. Most of the formations are highly fractured carbonates and are prone to severe to total losses. The ECS combination was successfully used to mitigate complete losses and continue drilling where, in some cases, as much as 90% circulation was regained.
Another application of this solution was also proposed for drilling an offshore well for an operator in East Africa. A formation that was severely fractured was to be encountered and total loss was expected. A circulating sub was recommended in the bottomhole assembly (BHA), and high concentrations of ECS were pumped. Losses were managed in most cases that were otherwise unmanageable with conventional LCMs. This enabled the operator to reach total depth (TD) and obtain necessary exploration information.
Studies of Cement Wiper Plugs Suggest New Deepwater Standards
Authors: Trogus M. , Farley D. , Gaspard G. 
Published: March 2015

Abstract
Well cementing is a crucial component of deepwater well construction, and a key to cementing success is the performance of the cementing plug. Plug performance is primarily based on the mechanical wiping efficiency and wear resistance of the plug. However, limited understanding of the performance has hindered the establishment of standards. While API RP10F provides recommended testing practices to evaluate the performance of cementing float equipment, it does not include cementing plugs.
This paper is the first published review of efforts to better understand cement plug performance and to establish industry standards. Through laboratory studies, it examines material loss in actual deepwater applications and evaluates the effect on wiping performance of cementing plugs. These studies provide the basis of a selection process for wear-resistant materials. The paper also examines methods of measuring wiping efficiency and overall plug performance. Based on these methods, a proposal is presented for establishing industry performance standards for setting cementing plugs.
Cementing wiper plugs provide a physical barrier to cement contamination by separating displacement fluid and wiping residual mud film and other materials from the inside surface of the pipe. Separation and wiping efficiency are directly related to plug wear resistance and to the process of balancing design to achieve optimal stiffness and pressure containment. This design balance is achieved through rigorous material testing and design refinement. Analysis of wiper cuttings samples has provided a clear understanding of the plug's ability to provide a physical barrier to separate fluids and how that affects the function of downhole tools. This cuttings evaluation has provided information on material loss and positive fin interference. Results of the evaluation are corroborated by field performance achieved in cementing lengths of casing greater than 16,000 ft.
Plug wear is of particular concern in long, high-volume, deepwater casing strings where it can lead to displacement errors and reliability problems for downhole pressure-actuated tools. These displacement errors are examined in field applications that precisely locate the plug at multiple points during the cementing process.
Hardbanding Compatibility Test Program to Stem Tool Joint Failures Caused by Reapplication of Incompatible Hardbanding
Authors: Koneti Srinivasa , Gokhale Samit 
Published: March 2015

Abstract
Hardbanding re-application on used tool joints is routinely performed to build up previously worn out hardbanding. Often, hardbanding reapplication is performed without checking the compatibility of the reapplied and previous hardbanding types. Different hardbanding types do not always work properly when applied over each other. This hardbanding incompatibility can lead to cracking, spalling and porosity of reapplied hardbanding. This can cause premature damage and failure of the reapplied hardbanding and even the mechanical failure of the tool joints themselves.
This paper presents case studies and lessons learned from the analysis of such failures. In every case, hardbanding reapplication was performed without checking the compatibility with the existing hardbanding. Metallurgical analysis showed that the failed tool joints had two different hardbanding layers and that the tool joint failures were caused by the incompatibility of the two materials. The new hardbanding cracked and chipped off from the outside surface of the tool joints and led to tool joint failures when the cracking propagated through the base material.
In addition to discussing hardbanding incompatibility failures, this paper also provides reapplication specification requirements and inspection guidelines needed to control the reapplication processes. To confirm compatibility of different hardbanding types, a compatibility testing program was created. This paper presents the details of this compatibility test program including discussions on application geometry, procedural control, metallurgical analysis and material testing needed to confirm compatibility.
Drilling With 100% Natural Gas Engines
Authors: McEvers Jon , Kent Bill 
Published: March 2015

Abstract
Antero Resources decided to convert the majority of its drilling operations from diesel to 100% natural gas fueled rigs in late 2012. By September 2014, ten of Antero's largest drill rigs were retrofitted with GE Waukesha rich-burn gas engines and fueled entirely by natural gas. By operating on field gas 50% of the time and LNG for the remaining 50%, Antero realized a savings of more than $72,000 per month on its gas engine rigs versus its comparable diesel fueled rigs. This paper presents how Antero successfully deployed rich-burn natural gas engines into its Patterson-UTI Energy and Precision Drilling drill rigs.
Blowout Well-Flow Simulation for Deepwater Drilling using High-Pressure/High-Temperature (HP/HT) Black-Oil Viscosity Model
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng 
Published: March 2015

Abstract
One of the major risks associated with drilling an oil well is a blowout, or an uncontrolled release of hydrocarbons, which can lead to significant financial loss, environmental damage, personnel injuries or even casualties, and shaken shareholder confidence. Numerical simulation can offer some insight into well-flow parameters and wellbore integrity during a blowout event. Therefore, it is a powerful tool in casing design, blowout-preventer (BOP) stack design, drilling-process design, and well-kill design.
In this paper, a field case was investigated using a commercial thermal and flow simulator. The effects of oil flow rate on wellbore temperature and pressure profiles were studied. Load analyses show that a blowout to atmosphere scenario is more detrimental to well integrity than a blowout to seafloor. In both scenarios, the maximum collapse load of the innermost casing increases with a decreasing blowout oil rate. This implies that if reservoir pressures are the same, deepwater wells with lower productivity indices will be more problematic in terms of well integrity.
Simulation results also show that the viscous friction heat loss becomes significant at very high oil flow rates. During a deepwater-well worst case discharge (WCD) blowout, it is so significant that the wellbore temperature increases toward the surface along the smallest flow passage. The situation is even worse if the blowout fluids are discharged to the atmosphere. The physical root cause is explained in terms of fluid heat balance.
A high-pressure/high-temperature (HP/HT) black-oil viscosity model was developed through modification of the Bergman-Sutton model. The HP/HT viscosity data of different crude oils with various API gravities were used to determine the model constant through regression. The effects of this HP/HT viscosity model are quantified in detail using the case-study data. The new viscosity model yields much higher accuracy in the HP/HT regime compared to other traditional, widely used models. Consequently, it facilitates higher certainty modeling and simulation of well discharge scenarios to satisfy current casing-design regulations in well exploration and development, from deepwater to ultra-deepwater conditions.
Wired Near Bit Underreamer Connects Measurement While Drilling Tools to Rotary Steerable System While Eliminating the Under Gauge Rathole at TD
Authors: Valverde Eduardo , Goodwin Alex 
Published: March 2015

Abstract
Simultaneous drilling and hole enlargement is a common practice in deepwater Gulf of Mexico projects where tighter casing tolerances are required. Hole enlargement via underreaming is the most common practice, because it provides a larger diameter hole to ensure that casing reaches its required total depth (TD). Hole enlargement creates sufficient annular space to allow casing to be delivered to planned depth as well as for a properly executed cement job. The most accepted bottom hole assembly (BHA) design for hole enlargement while drilling (HEWD) places an underreamer above both the measurement while drilling / logging while drilling (MWD/LWD) and rotary steerable system (RSS) packages. This placement ensures proper installation of the activation ball in the underreamer and connectivity of the RSS and MWD/LWD so that directional work can be executed. However, this placement also leaves up to 200 feet (61 m) of under gauge rat hole to total depth (TD), forcing the operator in many cases to make a second dedicated run to underream the remaining under gauge rat hole.
An alternative underreamer technology that is gaining interest is designed to run directly above the RSS, but below the MWD/LWD package. Known as the intelligent wired underreamer, this design allows for a much shorter under gauge rathole to TD, while circumventing several common deployment challenges with conventional underreamers. Historically, placing an underreamer below the MWD/LWD prevented the operator from pumping an activation ball through the restricted internal diameter of the MWD/LWD tools. Another challenge of placing the underreamer near the bit is the fact that connectivity is severed between the MWD/LWD and RSS, which makes it impossible to use certain RSS in the BHA.
A deepwater operator drilled a development well in the Gulf of Mexico which required such a solution to simultaneously drill and enlarge the 18 1/8” and 16 ½” sections of the wellbore to 22” and 20”, respectively. The intelligent wired underreamer, with its radio frequency identification (RFID) and pump-cycle activation capabilities, allowed the operator to run the underreamer directly above the RSS and below the MWD/LWD package and successfully activate and deactivate the underreamer, without ball drop. A wire through the underreamer connected the MWD/LWD and the RSS, providing full connectivity and directional control. And the use of an intelligent wired reamer in this application eliminated a potential round trip to ream the rathole and allowed the operator to successfully drill and ream both sections to planned TD.
Look Ahead Team MXS: Transforming Knowledge in Successful Operations
Authors: Rodríguez E. , Jiménez A. , Angel J. , Bedino H. , Scagliarini S. , Salinas N. , Valdiviezo F. , Mendoza P. 
Published: March 2015

Abstract
This paper describes how the creation of an innovative multidisciplinary team - the Look Ahead Team (LHT) - together with ad hoc new built processes and protocols, have greatly helped minimizing both the geological and drilling risks and their impact in the very complex wells currently being drilled in the Mesozoico, Exploration and Alliance projects in Southern Mexico (MXS). Also, it explains how the integration of different knowledge domains coupled with detailed technical scrutiny, subsurface visualization, modeling and simulation, thorough multilayers risk assessments, risk management techniques, real time data acquisition and continuous application of lessons learnt, have been delivering substantial savings to the drilling operations.
Wells can be classified as deep HP/HT and/or LP/HT wells.
The objective of the LHT is to visualize and analyze drilling related risks, to generate alerts and recommendations before a new hole section is commenced, so that undesirable and detrimental subsurface events are anticipated and prevented or minimized.
Drilling engineering, geology, geophysics, geomechanics and well placement are all represented in and form an integral part of the LHT. For each new well to be drilled, the geosciences' domain experts perform an integrated subsurface interpretation considering all current information available, offset wells and real time data.
The analysis performed is twofold: a forecast drilling scenario (well trajectory and placement) which is optimized based on the calibration attained through the iteration with existing (offset) wells using sophisticated modelling and newly created work protocols that allow effective multidisciplinary workflows, subsurface assessment and detailed risk analysis by hole section.
The main outcome of the analysis is to deliver a predictive ‘look ahead’ report which contains all risks identified at least 200 m ahead of the bit together with the risk analysis matrix and the corresponding prevention and mitigation plan. Also during the program execution, the LHT provides technical support to the engineering and operations teams anticipating the next action based on risk projection re-assessment using real data streaming.
The Look Ahead Team's newly implemented processes/workflows and innovative analysis methodologies, have been tested on 21 development wells and 3 exploratory wells for a total of 72 hole sections. In just one year from its foundation, unforeseen drilling events due to geological uncertainty were reduced by 90% achieving 10MMUSD worth of savings.
Assessment of the Validity of MWD Survey Accuracy Following Multistation Analysis
Authors: Hanak F. Chad , Wilson Harry , Gjertsen Morten 
Published: March 2015

Abstract
The authors are concerned that the claim of increased accuracy for MWD directional surveys processed using multistation analysis (MSA) may not always be valid, resulting in incorrect assumptions regarding the probability of well collision and target intersection. Very little information is available about the MSA methods currently in use. The only relevant published work identified by the authors is an SPE paper defining the minimum survey log conditions required to validate surveys against the ISCWSA MWD error model, but the requirements do not support assumptions of increased accuracy, post correction.
It was therefore decided to determine if MSA can be used to reliably increase survey accuracy. The study also evaluated the validity of using the published minimum requirements to validate data against a typical MSA enhanced error model. The mathematical technique of consider covariance analysis was used to quantify post correction position uncertainty, and compare it to typical MSA error model assumptions. The results were validated using monte carlo simulation.
The study showed that use of the published minimum data condition requirements to validate surveys against the increased accuracy claim typical of MSA error models is invalid. For the minimum requirements method to provide validation of such arbitrarily enhanced error models, new requirements must be defined specific to the MSA model. However, typical MSA error model assumptions are likely to result in requirements that can very rarely be met. Consider covariance analysis offers a reliable method of evaluating actual survey data against an arbitrarily enhanced error model on a case-by-case basis, which would allow more frequent use of the MSA error model.