bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of New Pitting Acceptance Criteria Using Axi-Assymetric Thread Models to Improve Service Life and Reduce Repair Costs of Rotary Shouldered Connections
Authors: Gokhale Samit , Oak Sushil , Lee Kang 
Published: March 2017

Abstract
Rotary Shouldered Connections (RSCs) are subjected to harsh downhole environments and aggressive fluids that can cause pitting damage. Pitting, especially in the thread roots, increases the likelihood of fatigue crack initiation and propagation. Currently, no industry standard provides quantitative analysis of the effects of pitting on the fatigue life of RSCs. This often leads to deployment of a conservative acceptance criterion of disallowing pitting in any thread roots; resulting in frequent repair and recuts of RSCs, and at times reducing the service life of the components.
This paper details the analysis performed and methods adopted to assess the effects of pitting on fatigue life of RSCs. Six API connections commonly used on small, medium, and large size drill pipe and bottom hole assembly (BHA) components were modeled. Finite Element Analysis (FEA) was used to examine stresses in different thread roots of these connections. Connections with and without stress relief features were analyzed. A methodology was developed to integrate the effects of stress concentration caused by a pit into the stresses obtained from FEA analysis.
It was found that the stresses in many thread roots, even with a pit, were lower than the stresses in the last engaged threads. This result was used to establish new pitting acceptance criteria allowing pitting in some thread roots as long as the stresses were lower than the maximum stress found in the last engaged threads.
This study provides a scientific approach towards assessment of pitting damage. The study shows that a significant number of threads could be allowed to have pitting without compromising the overall fatigue life. Based on these results, universal inspection criteria were developed covering all API connections to provide well-defined, consistent and user-friendly method of inspection. These new acceptance criteria will reduce the cost of frequent machining, repair and replacement of components.
A New Analytical Model for Jarring Analysis
Authors: Zhang Yuan , Samuel Robello 
Published: March 2017

Abstract
Extensive jar models currently exist. When a hammer hits an anvil in a jar, a strong stress wave is generated in the drillstring. Such jar models have significant limitations because most do not account for the stress wave in the lower collar. However, when the hammer hits the anvil, both the upper and the lower collars deform to resist impact from the hit. Thus, there are two stress waves generated in both the upper and lower collars at the same time. The stress wave in the lower collar is the key reason for such impact force at the stuck point.
This paper discusses a new analytical model for jarring analysis based on two directional propaganda stress wave theories. It assumes that the energy from the hammer divides into two parts; one part travels upward to ground and the other moves downward to the stuck point. An equation is proposed to calculate the maximum impact force that can be determined, despite whether the jar can move the stuck pipe. New equations are proposed to calculate the jarring period and impact force. This can help achieve the most effective jar placement in horizontal wells.
Additionally, this paper reveals that increasing the energy ratio in lower collar can enhance jarring effectiveness significantly. The stress in the lower collar can be enhanced by increasing its section area. Impact force at the stuck point differs from the impact force at the anvil. A stronger stress wave in the lower collar generates a larger stuck force at the stuck point.
A Simple Method for Identifying Fracture Initiation Pressure
Authors: Naidu R. N. , Rylance M. 
Published: March 2017

Abstract
A reliable interpretation of Fracture Initiation Pressure (FIP) provides key information for both efficient well planning and construction. With the trend towards drilling ever deeper offshore wells, depleted zones and more complex well paths, the available mud weight window continues to tighten, so an improved knowledge of the FIP becomes essential in enabling robust designs and risk reduction strategies that together promote safe and efficient operations.
A number of methods are currently used across the Industry to estimate FIP values for drilling and completion applications. These methods involve the direct interpretation of data from injection tests, such as Diagnostic Fracture Injection Tests (DFIT), Formation Pressure Integrity Tests (FPIT) or even Wireline Formation Tests (WFT). In this paper, the authors propose and present a simplistic yet effective approach to derive values for the FIP from such typical pumping test data. The method is based on long established principles linking the pressure, volume and in-situ rock properties of the system being tested.
This paper provides a number of examples to demonstrate the application and validity of the approach, including the consideration of scaled laboratory block tests, through to actual field data. The relationship between FIP, FBP and closure pressure is presented and discussed for all of these cases. The method is based on early-time wellbore stiffness considerations and as such complements and augments the more conventional fracture closure analysis approach from decline data. Using this technique, additional valuable information may be extracted even from only partially completed tests, where formation breakdown analysis by conventional means may either be impossible to perform or at best is somewhat inconclusive.
In summary, while there are many and varied techniques that have been widely developed in support of obtaining FIP, the quality, the repeatability and assurance of these approaches is often incomplete and can sometimes be misleading. The simplistic methodology that is outlined and presented here provides a complementary approach, with the potential to offer a more consistent estimation of this key pressure control parameter. The method also provides the possibility of identifying the FIP in those situations where the currently available data (quantity and/or quality) would suggest that conventional methods might well fail to deliver an unbiased interpretation.
Gas Influx into Drilling Fluids During Flow Check Operations as Affected by Gas Absorption Characteristics of the Drilling Fluid
Authors: Linga Harald , Bjørkevoll Knut Steinar , Skogestad Jan Ole , Saasen Arild 
Published: March 2017

Abstract
The paper addresses the gas loading characteristics of the drilling fluid and its influence of the gas influx rate during the flow check operation. In particular, the resulting fluid expansion in the wellbore annulus and the capability to detect gas kick at HPHT process conditions will be discussed for selected drilling fluids.
For the evaluation of the applicability of flow check operations for the detection of gas influx, the time response to the drilling fluid expansion during natural gas influx is addressed in terms of drilling fluid gas loading properties, influx severity and influx area.
The physical gas loading rate of natural gas into the drilling fluid is described as a first order kinetic mass transfer process including the gas loading capability for the multicomponent system of drilling fluid and natural gas, in addition to the gas influx characteristics at the wellbore–formation boundary.
When operating the fluid system of natural gas–drilling fluid in the liquid phase region, a continuous gas influx will at some point give more distinct expansion of the fluid mixture in the wellbore. This occurs for the maximum gas loading of the drilling fluid. Such distinct change in sensitivity in the volume expansion response is not encountered when operating the system of drilling fluid–natural gas in dense phase. For selected cases relevant for HPHT drilling, the volume expansion response during flow check operation is compared for drilling fluid with gas loading characteristics either representing single liquid phase or dense phase gas loading. With the methodology described it is readily shown that the interpretation and design of the flow check operation should be carefully selected when approaching dense phase conditions or if the gas loading capability of the drilling fluid is considerable. This is particularly important for oil-based drilling fluids featuring high gas loading capability.
Maximizing Tubular Capacity and Well Integrity Under Near-Yield Loading
Authors: Nowinka J. , Meijer G. , Miller S. 
Published: March 2017

Abstract
Achieving well integrity demands knowing how much loading your tubulars can withstand, but what happens when near-yield loading causes unexpected deformations that are not predicted by code design and conventional elastic design theory? It begs the question, are harsh operating conditions and narrowing design safety margins increasing the potential for well failures? Alternatively, can tubulars be safely pushed even harder without compromising well integrity?
This paper raises industry awareness, demonstrates material test results, and proposes steps to account for possible near-yield load effects so that well designs can fully use the available tubular material capacity and be cost effective without compromising the long-term integrity of the well. Examples of near-yield load scenarios leading to substantial plastic deformation observed in laboratory testing are presented, and ways to determine when those effects need to be considered in elastic design methods are proposed.
The paper illustrates the effects of near-yield loading on tubular deformations using results of mechanical testing on a P110 material sample under cyclic uniaxial and multiaxial load. Uniaxial load cycles with stress amplitude below the rated yield strength showed substantial growth of plastic strain in only a few cycles. Combined-load tests on small-scale tubular P110 specimens loaded with axial force and internal pressure cycles also demonstrated pronounced near-yield load effects.
We discuss the significance of material behaviors that trigger plasticity at stresses below the measured yield strength and contribute to severity of near-yield load effects; such as changes in the stress-strain response due to elevated temperature exposure, directional dependence of material properties, and cyclic softening. We draw conclusions on how tubular material properties and operational loading extremes need to be assessed and balanced to maintain structural integrity of wells in anticipated operational scenarios.
To maximize capacity of completion tubulars, the complexity of near-yield load effects needs to be characterized with technically rigorous yet practical means. This paper points to relatively simple material tests for determining the propensity for near-yield loading effects of common OCTG materials, and suggests initial considerations for incorporating near-yield load considerations in tubular design.
Improving Casing Integrity by Induction Brazing of Casing Connections
Authors: Ernens D. , Hariharan H. , van Haaften W M. , Pasaribu H. R. , Jabs M. , McKim R. 
Published: March 2017

Abstract
Brazing technology allows metallurgical joining of dissimilar materials using a filler material. In this paper brazing technology applied to casing connections is presented. The initial application was triggered by challenges with mechanical and pressure integrity after expansion of casing connections. Creating a strong bond between the pin and the box could resolve this. Brazing was selected because of the combination of ductility and high bond strength and the relatively fast process to create the bond. The brazing process or temperature-torque-time process (TTT) is performed using regular casing connections, a filler material deposited by flame spray and a flux. Two processes were developed, one for expandable (VM50) grade material and one for quenched and tempered grade material. For this a rig ready (CLASS 1 DIV 1) prototype brazing system was developed consisting of an induction coil as the heat source, an environmental chamber to shield the hot work, and a modified power tong to provide torque. The results of a series of brazing trials on 8-5/8″ and 9-5/8″ casing connections are presented. The brazed connections were subsequently capped end pressure tested, expanded (when applicable) and load cycled. It is concluded that both processes produced leak tight casing connectors before and after expansion (when applicable) as shown by full scale tests
New Optical Sensor System for Improved Fluid Identification and Fluid Typing During LWD Sampling Operations
Authors: Cartellieri Ansgar , Kischkat Tobias , Sroka Stefan , Meister Matthias 
Published: March 2017

Abstract
In recent years different new services for formation sampling while drilling operations were introduced. The provided and implemented technology is primarily focused on the delivery of representative single-phase fluid samples. The formation sampling while drilling tools are equipped with various unique fluid identification sensors. These sensor modules deliver multiple physical properties and are commonly used for clean-up monitoring. Due to the extended downhole time during long drilling runs and the tough drilling condition ruggedized sensor elements have to be implemented. In addition, the same challenges regarding pressure, temperature and size as with wireline tools have to be considered.
The described logging-while-drilling (LWD) fluid analysis and sampling service is now extended by delivering optical absorbance spectroscopy and fluorescence measurements under in-situ conditions. This sensor system is added to the already existing sensor elements like pressure and temperature as well as measurement cells for density, viscosity, sound speed and optical refractive index. In addition, the lately introduced compressibility value derived from the electro-mechanical pump offers a bulk measurement, where localized sensors observe scattered data. As while drilling applications are often limited by the reduced bandwidth between the downhole tool and the surface acquisition system readings from the new optical sensor modules will be added to the fluid-typing algorithm, previously based on density, compressibility, refractive index and sound speed measurements, for improved predictions during sampling operations.
This technology should expand the application of fluid analysis in the downhole environment, gaining a deeper understanding of the reservoir fluid as well as improving the reservoir characterization and classification. With the new optical sensor system which provides distinct wavelength measurements in the visible, near infrared as well as ultraviolet range, a more detailed analytics of the formation fluid is possible. It will enhance the differentiation between water based mud, formation water and injection water as well as oil based mud and oil. It improves contamination monitoring and delivers a more detailed chemical composition while sampling. This new sensors will increase the success of fluid analysis only jobs.
Field examples will demonstrate the new sensor capabilities and will evaluate the data accuracy. The data interpretation allows for a broad comparison between different environments and the according sensor behavior. The review includes results from different reservoirs in various regions around the world.
An Industry-First 7-5/8 in. Drill Pipe Like Tubular Facilitates Deep Offshore Completions and Interventions by Saving Time and Reducing Cost.
Authors: Corbin Kevin , Begnaud Taylor , Elliott Greg , Sanclemente Leianne , Babineaux Joshua , Brock Jim , Plessis Guillaume , Muradov Andrei 
Published: March 2017

Abstract
Tubulars with gas-tight, rotary-shouldered connections are used as the conduit between the surface vessel (rig) and subsea wellheads in deepwater operations. Requiring no specialized tools and using standard rig equipment, they provide a fast, safe, and cost effective way to run completion landing strings and intervention pipe. Tubulars for these operations must provide a large internal drift diameter to allow for clearance of the wellhead crown plug and installation of completion components. These strings have been limited to 6-5/8 in. pipe allowing for a maximum drift diameter of 5-1/2 in., which is insufficient to run and retrieve the wellhead crown plugs of many large ID subsea trees. Trees with larger crown plugs require operators to use casing tubulars increasing deployment time, requiring casing running crews, incurring higher repair costs and time, thereby increasing overall costs.
A completion landing string (CLS) was developed using a 7-5/8 in. pipe and a built-for-purpose, large drift, gas-tight, pressure-rated, rotary-shouldered connection (7-5/8 CLS). This new connection technology optimized the outside diameter and make-up torque to be compatible with the iron roughnecks and pipe handling equipment of the current Gulf of Mexico rigs.
Product development and performance validation is detailed with a special emphasis on the enabling connection technology. The paper expands on manufacturing challenges and design choices made to assure ease of rig operations, including modifications to slips and elevators. Finite element analysis (FEA) and physical testing to validate performance are described. Steps taken before the initial deployment to assure compatibility with the rig equipment are explained. Finally, the paper will show data from the offshore field trials and initial deployments. Lessons learned are shared.
This industry-first, purpose–built, gas-tight completion and intervention tubular provides 6-1/8 in. internal drift diameter and can be safely deployed using conventional pipe make-up and handling equipment reducing overall cost.
Well Collision Avoidance Management and Principles
Authors: Sawaryn S. J. 
Published: March 2017

Abstract
The well collision avoidance management and principles presented in this paper are a culmination of the work and consensus of industry experts from both operators and service companies in the SPE Wellbore Positioning Technical Section (WPTS). This is not a new subject, but current guidance is disparate, company specific and occasionally contradictory. As a result, the guidance can be difficult to understand and implement. A further aim was to drive standardization of the well collision avoidance rules, process and nomenclature throughout the industry. Standardisation improves efficiency and reduces implementation errors.
The consequences of an unplanned intersection with an existing well can range from financial loss to a catastrophic blow-out and loss of life. The process of well collision avoidance involves rules that determine the allowable well separation, the management of the associated directional planning and surveying activities and assurance and verification. The adoption of a particular minimum allowable separation rule, no matter how conservative, does not ensure an acceptably low probability of collision. Many other factors contribute, such as the level of compliance by office and rig personnel with collision avoidance procedures, and the completeness and correctness of the directional database. These factors are all connected.
The material is split into eight sections, each dealing with a critical element in the collision avoidance process. Examples are presented to highlight good implementation practice. This aligned approach will dispel some of the current confusion in the industry over well collision avoidance; improve efficiency when planning and executing wells and build industry focus on the associated collision risks when drilling. The Technical Section is also supporting the current development of API RP78.
This is the first of two papers. The second paper will cover the minimum allowable separation rule and its application, assurance and verification.
Developing Remote Operations Capabilities in the US Land Market
Authors: Huckeby Joshua 
Published: March 2017

Abstract
The development of remote operations work in the US land market has occurred more slowly than in other markets because of resistance to change at the rig site, continually evolving approaches to drilling programs, and significant increases in penetration rates over the past several years. Because the barriers to entry in the US land directional and measurement-while-drilling (MWD) market are low and the accessibility to the wellsite is high, typical risk mitigation and personnel retention aspects of remote operations play a smaller role in the acceptance of remote operations. The decrease in oil prices from late 2014 to 2016 renewed interest in remote operations to reduce cost.
Successful remote operations in the US land market required revising the traditional remote operations model. Several factors remained similar to the established practices, such as efficient communication networks and intelligent backups of these systems, reducing on-site personnel, and establishing dedicated remote operations center (ROC) workstations. Other factors, however, have changed, including staging a single operator at the wellsite to troubleshoot and maintain interpersonal communication, and developing software solutions to enable the remote operator to operate up to four jobs simultaneously at instantaneous penetration rates of more than 1,000 ft/hr (300 m/hr).
A large service company successfully performed more than 140 MWD remote-operations wells in the Midwest/Rocky Mountain area during the first year of remote operation. During implementation, it was discovered that remote operations are less a technical challenge, and more a value challenge requiring buy-in from all stakeholders. In terms of drilling efficiency, the results seen during this project were significant, with one-third fewer trips for MWD failure, as well as significant reductions in MWD downtime while drilling.
This paper discusses the implementation of remote operations, resulting lessons learned, and optimization opportunities. These lessons learned and optimization opportunities include the challenges of integrating remote operations into a ROC and why personnel selection is crucial to the long-term success of remote operations. The paper also describes how the integration of specialists from several disciplines enhances both remote-operations efficiency and customer experience. Finally, it provides a long-term outlook on US land remote-operations development.