bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cement Placement with Tubing Left in Hole during Plug and Abandonment Operations
Authors: Aas Bjarne , Sørbø Jostein , Stokka Sigmund , Saasen Arild , Statoil Rune Godøy , Lunde Øyvind , Phillips Conoco , Vrålstad Torbjørn 
Published: January 2016

Abstract
Well abandonment operations can be very time-consuming and costly, and thousands of wells need to be permanently plugged and abandoned offshore Norway during the upcoming years. One possible way to reduce costs during P&A operations is to leave most of the production tubing in the well, as this would save significant rig time. A major concern with such an approach is, however, whether the cement will properly displace the original fluid, due to lack of tubing centralization and possible unfavorable flow dynamics in the annulus. In this paper, we demonstrate by full-scale experimental tests that it is possible to obtain good cement placement when the tubing is left in the hole, with and without control lines.
Full-scale tests have been performed with both conventional and expandable cement to determine the sealing ability of annulus cement when tubing is left in hole. The quality of the cement placement was evaluated by pressure tests with water; where leakage rates and pressure drops over the test sections were recorded, and by visual inspection after cutting the test assemblies at different places. It is seen from the experiments that cement is well placed in the annulus when tubing is left in hole, but some microannuli are detected.
Industry Initiative – Testing, Certification & Training of Drilling Supervisors to Improve Safety and Performance
Authors: McAteer Peter , Dimitriadis Klisthenis , Taylor Charlie , Kelly Chris , Selbie Gary , Warren Andrew , Whatson Neal , Warner Randy , Holloway Pam 
Published: January 2016

Abstract
This paper outlines a new industry initiative and system supported by a group of Operators to reduce NPT and enhance safety performance.
It addresses competency of Well-Site Supervisors with a group of Operators aspiring to create industry-wide certification. Its paradigm is Well Control Certification which it will complement, addressing all other areas within both drilling and completions.
Competence and experience validation requires a systematic, reliable and repeatable approach. The paper will outline the challenges and response of an Operator group to Well-Site Supervisor Testing, Certification and Training.
The Vision is to set the hallmark for quality Well-Site Supervisors globally by providing regularly updated certification.
The objective is to: Prevent repetitive mistakes that cost the industry $billions each yearDifferentiate reliable people and support those that need assistanceMeasure reactions to simulations of events that occurred by presenting them as they unfold (to avoid hindsight engineering)Provide tools to improve and measure the individual's developmentShare the resource of quality graded Well-Site SupervisorsIncorporate ‘Human Factors’ to test interaction
The downturn represents a unique opportunity to set a new standard for an upturn when there will be shortages of quality personnel. Operators will be able to identify qualified personnel and train those that don't yet meet requirements, providing more quality personnel to the industry.
Improved Cement Plug Placement Method Resulting in Reduced Rig Time
Authors: Ahrenst A. , Grosshans C. , Martinez Melo A. , Suarez Jerez S. C. 
Published: January 2016

Abstract
Setting of cement plugs is generally perceived as a straightforward concept and simple operation. In reality, successful placement of a cement plug continues to be more difficult than traditionally thought due to the increasing challenges in extreme drilling environments. In today’s deepwater environment, plugs are often set at depths in excess of 30,000 ft and lengths of 1,500 ft and even longer. Despite significant progress on how to simulate cement plug placement, there may still be uncertainties as to the downhole parameters such as openhole geometry, lithology, pore and fracture gradients, depth of loss zone, downhole mud properties, and fluid design limitations for spacer and slurry. Due to these uncertainties, it may not always be preferable or even possible to set a plug using the traditional balanced plug technique. An alternative plug-setting technique that has been used successfully for many years is the internal blowout preventer (IBOP) method for which all the cement is placed into the annulus before pulling out of the plug. In this study, we analyze the advantages and disadvantages of the IBOP method. We also analyze field examples on an improved technique similar to the IBOP method, which, in this paper, is referred to the modified IBOP method. This method has all the advantages of the IBOP method while allowing for the use of mechanical separation of fluids, which is critical to control downhole contamination, especially for small and deep-set plugs.
A New Method to Mitigate Annular Pressure Buildup by Using Sacrificial Casing, Case Study: A Deepwater Well in Indonesia
Authors: Rizkiaputra Ricko , Siregar Ronny , Wibowo Teguh , Mabunga Shodji 
Published: January 2016

Abstract
For the subsea wells, the only accessible annulus is the annulus between production tubing and production casing or liner. When trapped annular fluid heats up, the fluid expands and will increase the annular pressure. Should the annulus between the surface and production casing gets trapped, the pressure buildup on this annulus would put the integrity of the well in jeopardy.
In this study, the tubular design approach is used to mitigate the annular pressure buildup by utilizing a section of lower grade casing installed on the outer casing (sacrificial casing) that immediately covers the inner casing being protected and keeps its integrity intact.
In selecting the sacrificial casing, three main parameters are needed, these are; the reservoir condition, formation characteristic, and wellbore configuration. These parameters are fed to a wellbore thermal simulator/stress analyses software, in order to create the well model with related pressure and temperature conditions. Iterative annular pressure buildup (APB) analyses throughout the life cycle of the well are then conducted in order to determine the suitable properties of the sacrificial casing. If the property of the sacrificial casing satisfies all expected loading conditions and protects the inner casing string, the design is deemed acceptable and the sacrificial casing becomes a part of the final well configuration.
This case study uses a deepwater well in Indonesia in order to apply the sacrificial casing method to mitigate the uncontrolled APB between the 20″ surface casing and 13 5/8″ production casing. A 20″ 154ppf X-56 section was selected as the sacrificial casing. In order to evaluate the effectiveness of the sacrificial casing throughout the life of the well, the various well scenarios covering the drilling operations, production operations and worst case discharge (WCD) events were evaluated. The simulations were conducted using proprietary commercial software having wellbore thermal simulator/stress analyses capability. This study suggests that utilizing a sacrificial casing to mitigate uncontrolled APB is sound engineering approach to keep the well integrity intact.
A Method for Determination of Stress and Fatigue in Risers and Wellheads
Authors: Horn Harald , Saasen Arild , Skogvang Arnljot 
Published: January 2016

Abstract
The paper presents a new and novel non-destructive method for measuring deterioration and cracks in steel structures. Results from stress and fatigue tests with different full scale structures are presented and related to real applications with respect to life-time prediction. Conventional cyclic loading test of riser-pipe elements are documented herein for confirmation of the method.
The subject method functions as follows: The material properties magnetic permeability and electrical conductivity, and changes in these, are determined by analyzing the measured voltage response to injected electric pulses. The response is transient voltage drop signals, measured under various conditions, and is the basis for calculating parameters representing the stress, fatigue and crack nucleation and crack development in the materials. The degree of material degradation can be used to calculate operational lifetime.
The method has been tested and verified for different types of stress and fatigue loads in different steel alloys. High sensitivity to elastic stress and early detection of permanent changes for high-cycle fatigue testing have been demonstrated with fatigue tests of workover riser pipes. High sensitivity to remanent stress, i.e. the steel's ability to "remember" stress (elastic) is a feature that is proportional to the maximum stress occurred since last measurement. On risers, measurement devices can be installed to give the actual condition of the steel for the most exposed locations. Additionally, this information can be used to calibrate the mathematical models for estimating the condition of the whole riser in order to reduce the uncertainty of estimates.
A Challenging HPHT Operation Supported by Dynamic Real Time Simulation, Forecasting and 3D Visualization
Authors: Nabavi Josef , Rommetveit Rolv , Wessel Just Sverre , Scott Laurie 
Published: January 2016

Abstract
Dynamic Real Time Simulation, Forecasting and 3D Visualization was utilized extensively in support of a very challenging HPHT drilling operation in the Norwegian Sea. The well was a vertical exploration well in the Haltenbanken area.
In preparation to the operation, an advanced training session was performed using a dynamic downhole training simulator linked to a topside rig simulator, for training of the drilling teams.
A real-time link was established with the operation, and WITSML data in addition to all well, fluid and string data was streamed into a dynamic, real-time simulation system. This simulation system provided the following; RT dynamic modelling of the pressure (ECD) and temperature profile in the wellbore; the cuttings distribution and its effects on the ECD;Automatic look-ahead simulations of ECD and temperatures on the fly was performed with the calibrated models as support for decisions.RT profiles of simulated versus measured pressure at the PWD, and simulated versus measured standpipe pressureRT dynamically updated 3D Visualization of the downhole wellbore with a continuously updated risk picture made available for the drilling teams.
Seamlessly linked to the RT system was a sophisticated what-if and planning model. 24 hour forecasting of operation was provided every day, and this gave a very good indication of future possible operational impacts. In addition to 24 hours forecasting, pre-planning simulations of upcoming sub-operations as well as what-if simulations on the fly were performed. The results from these simulations were used to update the risk register and made available in the 3D Visualization window.
Three specific cases will be discussed in the paper; Pre-simulation of running the 9 7/8″ casingPre-simulation of cementing the 9 7/8″ casingRT modeling of ESD in case of mismatch between rig calculated and measured values
In these cases the simulations provided valuable results which increased the risk awareness and prevented problems.
The paper will also discuss the RT 3D Visualization and its impact on reducing risks and communicating the dynamic risk picture.
The total simulation system with infrastructure, models and challenges will also be presented.
The operation was successful, and the results from the simulation system was a contributor to this.
A New Sour Service 125 ksi SMYS Drillpipe with Sour Service 120 ksi SMYS Tool Joints for Use in Sour Gas Drilling or Non-Sour Offshore Intervention Riser Applications Requiring Higher Load Capacities
Authors: Hehn Lucien , Uttecht Amie , Jellison Michael , Sanclemente Leianne , Delahoussaye Mike 
Published: January 2016

Abstract
The term "sour" is used to refer to drilling environments containing hydrogen sulfide (H2S). In sour wells, H2S causes sulfide stress cracking (SSC) in carbon low-alloy steels under tensile stress. A form of hydrogen embrittlement, SSC causes sudden, brittle fracture in drillpipe. To combat the effects of H2S exposure, sour service drillpipe has been manufactured to meet IRP Volume 1 - Critical Sour Drilling specifications. IRP requires 75 ksi (SS75), 95 ksi (SS95), or 105 ksi (SS105) tubes with all three grades using 110 ksi SMYS tool joints for use in sour operations. However, these lower yield strength IRP grades have limited load capacity which restricts drilling parameters such as total depth (TD) and margin of overpull.
Using advanced steel heat treatment methods, a 125 ksi SMYS grade sour service drillpipe has been developed. The 125 ksi tube is mechanically incompatible with the standard 110 ksi IRP sour service grade tool joint because of the large difference in yield strength between the two components. Therefore, a new class of sour service tool joint with an SMYS of 120 ksi was required for the 125 ksi sour service tube. This new higher yield strength tool joint needs to meet the same level of SSC-resistance as the 110 ksi IRP tool joint, i.e., pass testing in solution A method A of NACE TM0177 (100% H2S @pH = 2.7, 720 hour test) at a testing stress of 65% of SMYS. Like the high yield strength 125 ksi tube, advanced heat treatment methods were required to achieve SSC-resistance in the higher yield strength tool joint.
A second application for the 125 ksi drillpipe is as an offshore drillpipe-based intervention riser for non-sour wells. Currently, 105 ksi drill pipe grades are often used but increased demands on load capacity (up to 1,000 kips) makes the 125 ksi drillpipe an attractive alternative. The 125 ksi drillpipe also meets recommended hardness limitations placed on offshore risers in specification API RP 17G (Recommended Practice for Completion/Workover Risers).
This paper introduces an SSC-resistant 125 ksi drillpipe with SSC-resistant 120 ksi tool joints and presents the results of NACE TM0177 testing of this new technology. The new 125 ksi drillpipe will allow for increased load capacity over IRP SS105 ksi grade drillpipe in drilling environments with moderate to low concentrations of H2S. In addition, it can serve as an improved substitute over 105 ksi drillpipe-based offshore intervention risers due to its increased load capacity and controlled hardness.
Long Reach Well Concept
Authors: Stokka Sigmund , Cayeux Eric , Gardner David , Kragset Steinar , Lohne Hans Petter , Randeberg Erlend , Skadsem Hans Joakim , Aas Bjarne , Kyllingstad Henrik , Larsen Torgeir , Saasen Arild 
Published: January 2016

Abstract
Current Extended Reach Drilling (ERD) well technology limits the well lengths to roughly 12 km with a horizontal departure of approximately 10 km. This paper presents a concept that enables simultaneous drilling and completion with an aim to substantially extend well reach and with an ultimate objective of constructing 30 km long production wells. Longer reach wells can be used to drain remote reserves using existing production facilities, as well as provide a means to access reservoirs located beneath environmentally sensitive areas.
The key technology elements that enable the concept to construct long reach wells are multiple sliding packer traction units in combination with a dual casing drilling system, comprised of a casing with an inner tubing. The sliding packer traction units provide two primary functions; continuous well control along the length of the borehole and traction to overcome axial friction. In addition, the traction packers provide a stable bottom-hole drilling platform avoiding the occurrence of drilling instabilities such as stick-slip, which can damage conventional bottom-hole assemblies and the drill bit in particular. The dual casing provides the conduit for drilling fluid circulation to the bit and cuttings transport to surface. The drilling fluid is pumped through the annulus formed between the casing and inner tubing. The drill cuttings are transported to surface through the inner tubing, ensuring efficient cuttings transport with a low-pressure loss.
The concept has been developed through a five-year project, kicked off in 2010. A prototype has been built and tests have shown that each sliding packer traction unit is able to push the drill bit or pull a completion string with a large axial force in excess of the estimated requirement. In the paper, elements of the system are described in detail and the results of the full-scale yard tests are presented.
The concept represents a new well construction method incorporating advanced completion technology. It enables drilling and completion of long reach wells and can operate in areas with complex pressure regimes, such as can occur from pressure depletion due to production or pressurizing as a result of the injection of water or gas. Well control is provided by packers placed in pairs that seal off the annulus at predefined intervals along the drill string. Production takes place through a large inner diameter. It is a well construction method with no flat time.
An Instrumented Topdrive Sub System: Enabling Greater Drilling Efficiencies via Innovative Sensing Capabilities
Authors: Bryant Thomas M. 
Published: January 2016

Abstract
While innovations and advances in drill rig and downhole drilling technology have enabled operational efficiencies and productivities in drilling far beyond that achieved even a decade ago, a large proportion of drill rigs today still lack suitable instrumentation that can be utilized to achieve a higher level of drilling performance. Operating with the disadvantages associated with inadequate, inferior, sometimes poorly maintained, and often uncalibrated rig sensors, these rigs are unable to achieve the efficiencies increasingly being demanded by operators and owners. To address this situation, a single point of service has been developed that contains a suite of calibrated and accurate surface rig sensors for acquisition of measurements essential for operations such as drilling optimization. These sensors, housed within an instrumented surface sub, include block height; drillstring tension, torsion, bending moment, bending angle, and rotation speed; mud flowrate, density, pressure and temperature; and drillstring vibrations. The sensor measurements are direct, calibrated, acquired simultaneously at user-configured sampling and recording rates, and possess degrees of accuracies well beyond those of standard rig instrumentation.
Utilizing aerospace, medical, industrial, and proven oilfield technologies, such as acoustics, laser range finding, thin-film strain gages, and product miniaturization, an instrumented sub system is being developed to provide for direct acquisition of the most critical measurements required for drilling optimization. The sub was designed to be located at the top of the drillstring. Primary design considerations included high accuracies of measurements, with traceability of calibrations; simultaneous acquisition of all measurements; preservation and extension of battery life via sophisticated sensor and battery management; very low bit error rates and robustness of radio telemetries; and ease of use tied with flexibility of user customizations.
Early and limited testing of the system indicates accuracies of measurements of hookload, torsion, bending moment, rotation speed, pressure and temperature to be in the range of 1% or better. While characterizations of accuracies for the laser-derived height measurement, volumetric flowrate, and mud density are in the process of being determined, these measurements are innovative and enabling with respect to the unique location in which they are sensed. The acquisition of synchronous measurements facilitates and enhances processing, manipulation and ultimate interpretations of mixed data. Data are telemetered wirelessly from the sub to a surface-based computing and display device via a robust radio communications channel designed and being tested for bit error rates of &lt;1/10,000.
Integration of Time-Based Dynamics Simulation with Milling and Underreaming System to Implement Reliable Single Trip Solution in Plug and Abandonment Operation
Authors: Wang Yaou , Vos Marco , Karimpour Alireza , Fearn Murray , den Besten Hendri , Stanko Tomasz , Bain Jim , Shen Yuelin , Stokes David , Issa Ali , Khan Zafar 
Published: January 2016

Abstract
A trip-saving well abandonment technology was recently developed to prepare wellbores for the installation of abandonment barriers where poor annular cement quality exists at the required plug location. The trip-saving technology uses a hybrid section milling and underreaming single-trip BHA design to remove casing from the wellbore and underream to virgin formation, eliminating all potential leak paths from the cement barrier. This single-trip BHA is a step change in conventional industry practice whereby the service is typically provided in two dedicated trips: one to mill and one to underream. This paper presents the successful application of the single-trip BHA with the aid of a time-based simulation system in a challenging environment.
The single-trip BHA was required by an operator in The Netherlands, where challenging well conditions and abandonment requirements resulted in the need for underreaming to a 20-in hole size from a wellbore tool restriction OD of 8.5-in. This ultrahigh-ratio reamer arm opening generates significant dynamic loadings on the BHA. To achieve a successful single-trip operation, a 3D time-based drilling dynamic simulation system was employed as a technical solution to ensure: Maximum ROP to meet customer requirements while balancing with BHA limits of operation.Intended underreamer behavior to create a concentric and balanced hole opening across the full hole profile.
The dynamic simulation first carried out a prerun parametric sensitivity study to identify the optimal parameters with high ROP and low vibration/stick-slip ratio. Then the underreamer off-center distance was examined to ensure sufficient new virgin rock exposure in all directions for subsequent cement plug setting.
This dynamic simulation outcome was the creation of a prejob planning roadmap which enabled the job to be executed seamlessly at the rig site whilst achieving the customer Plug and Abandonment (P&A) objectives and ensuring the optimal utilization of each component of the single-trip BHA. The prejob planning roadmap was calibrated against operational performance by recorded stable operation data, observed good reamer arm dull conditions, and good caliper-logged hole quality. In addition, the field data were found to be highly in line with the simulation predictions, validating the accuracy of the time-based dynamic simulation system.
The single-trip operation saved the operator more than 49 h of rig time in abandoning the well. The successful application demonstrated the capability of not only the single-trip BHA, but also the calibrated dynamic simulation which saved substantial rig time and delivered a reliable single-trip service. The the successful operation not only reduced operator costs, but also reduced HSE exposure with less BHA handling on the rig floor.